e424b3
Filed pursuant to Rule 424(b)(3)
Registration No. 333-137441
PROSPECTUS
Offer to
Exchange
$300,000,000
71/2% Senior
Notes due 2013
that have been registered under the Securities Act of 1933
for any and all
$300,000,000
71/2% Senior
Notes due 2013
This Exchange Offer will expire at 5:00 P.M.,
New York City time, on November 9, 2006, unless
extended.
We are offering to exchange an aggregate principal amount of
$300,000,000 of registered
71/2% Senior
Notes due 2013, which we refer to as the new notes, for any and
all of our original unregistered
71/2% Senior
Notes due 2013 that were issued in a private offering on
April 24, 2006, which we refer to as the old notes.
Terms of
the exchange offer:
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We will exchange all outstanding old notes that are validly
tendered and not withdrawn prior to the expiration of the
exchange offer for an equal principal amount of new notes.
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The terms of the new notes are substantially identical to those
of the old notes, except that the transfer restrictions,
registration rights and special interest provisions relating to
the old notes do not apply to the new notes.
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You may withdraw tenders of old notes at any time prior to the
expiration of the exchange offer.
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The exchange of new notes for old notes will not be a taxable
transaction for U.S. federal income tax purposes.
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We will not receive any proceeds from the exchange offer.
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The new notes will be eligible for trading in the Private
Offering, Resales and Trading Automatic Linkage (PORTAL) Market.
SM We do not intend to apply for a listing of the new notes on
any securities exchange or for their inclusion on any automated
dealer quotation system.
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See Risk Factors beginning on page 19 for a
discussion of risks you should consider in connection with the
exchange offer.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
We may amend or supplement this prospectus from time to time by
filing amendments or supplements as required. You should read
this entire prospectus and related documents and any amendments
or supplements to this prospectus carefully before making your
investment decision.
The date of this prospectus is October 10, 2006.
TABLE OF
CONTENTS
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Page
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ii
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iii
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1
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19
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33
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103
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116
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118
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119
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121
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169
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169
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170
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170
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171
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F-1
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THIS PROSPECTUS IS PART OF A REGISTRATION STATEMENT WE
FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, OR SEC. IN
MAKING YOUR INVESTMENT DECISION, YOU SHOULD RELY ONLY ON THE
INFORMATION CONTAINED IN THIS PROSPECTUS, IN THE ACCOMPANYING
LETTER OF TRANSMITTAL OR THE INFORMATION TO WHICH WE HAVE
REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
ANY OTHER INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED
INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY
BE USED WHERE IT IS LEGAL TO EXCHANGE THE OLD NOTES. YOU SHOULD
NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS
ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT COVER
OF THIS PROSPECTUS.
Until January 8, 2007 (90 days after the date of
this prospectus), all dealers that effect transactions in these
securities, whether or not participating in this exchange offer,
may be required to deliver a prospectus. This is in addition to
the dealers obligation to deliver a prospectus when acting
as underwriters and with respect to their unsold allotments or
subscriptions.
i
CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Various statements in this prospectus, including those that
express a belief, expectation, or intention, as well as those
that are not statements of historical fact, are forward-looking
statements. The forward-looking statements may include
projections and estimates concerning the timing and success of
specific projects and our future production, revenues, income
and capital spending. Our forward-looking statements are
generally accompanied by words such as may,
will, estimate, project,
predict, believe, expect,
anticipate, potential, plan,
goal or other words that convey the uncertainty of
future events or outcomes. The forward-looking statements in
this prospectus speak only as of the date of this prospectus; we
disclaim any obligation to update these statements unless
required by securities law, and we caution you not to rely on
them unduly. We have based these forward-looking statements on
our current expectations and assumptions about future events.
While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to
significant business, economic, competitive, regulatory and
other risks, contingencies and uncertainties, most of which are
difficult to predict and many of which are beyond our control.
We disclose important factors that could cause our actual
results to differ materially from our expectations under
Risk Factors, Managements Discussion and
Analysis of Financial Condition and Results of Operations
and elsewhere in this prospectus. These risks, contingencies and
uncertainties relate to, among other matters, the following:
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the volatility of oil and natural gas prices;
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discovery, estimation, development and replacement of oil and
natural gas reserves;
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cash flow, liquidity and financial position;
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business strategy;
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amount, nature and timing of capital expenditures, including
future development costs;
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availability and terms of capital;
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timing and amount of future production of oil and natural gas;
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availability of drilling and production equipment;
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operating costs and other expenses;
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prospect development and property acquisitions;
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risks arising out of our hedging transactions;
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marketing of oil and natural gas;
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competition in the oil and natural gas industry;
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the impact of weather and the occurrence of natural disasters
such as hurricanes, fires, floods and other catastrophic events
and natural disasters;
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governmental regulation of the oil and natural gas industry;
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environmental liabilities;
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developments in oil-producing and natural gas-producing
countries;
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uninsured or underinsured losses in our oil and natural gas
operations;
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risks related to our level of indebtedness;
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our merger with Forest Energy Resources, including strategic
plans, expectations and objectives for future operations, and
the realization of expected benefits from the
transaction; and
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disruption from the merger with Forest Energy Resources making
it more difficult to manage Mariners business.
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ii
WHERE YOU
CAN FIND MORE INFORMATION
We file annual, quarterly and current reports, proxy statements
and other information with the SEC. Our SEC filings are
available to the public over the Internet at the SECs web
site at www.sec.gov. You also may read and copy any document we
file at the SECs public reference room in
Washington, D.C. Please call the SEC at
1-800-SEC-0330
for further information about the public reference room. Reports
and other information concerning us can also be inspected at the
offices of the New York Stock Exchange, 20 Broad Street,
New York, New York 10005. Our common stock is listed and traded
on the New York Stock Exchange under the trading symbol
ME.
You may request a copy of these filings, which we will provide
to you at no cost, by writing or telephoning us at the following
address: Mariner Energy, Inc., One Briar Lake Plaza,
Suite 2000, 2000 West Sam Houston Parkway South,
Houston, Texas 77004. Our phone number is
(713) 954-5555.
Our website address is www.mariner-energy.com. The information
on our website is not a part of this prospectus.
We are filing a registration statement on
Form S-4
to register with the SEC the new notes to be issued in exchange
for the old notes and guarantees thereof. This prospectus is
part of that registration statement. As allowed by the
SECs rules, this prospectus does not contain all of the
information you can find in the registration statement or the
exhibits to the registration statement. You should note that
where we summarize in the prospectus the material terms of any
contract, agreement or other document filed as an exhibit to the
registration statement, the summary information provided in the
prospectus is less complete than the actual contract, agreement
or document. You should refer to the exhibits filed to the
registration statement for copies of the actual contract,
agreement or document.
iii
PROSPECTUS
SUMMARY
This summary highlights information appearing in other
sections of this prospectus. It does not contain all of the
information you may wish to consider before participating in the
exchange offer. We urge you to read this entire prospectus to
understand fully the terms of the notes and other considerations
that may be important to you in making your decision regarding
the exchange offer, including the Risk Factors
section beginning on page 19 of this prospectus. As used in
this prospectus, unless the context otherwise requires or
indicates, references to Mariner, we,
our, ours, and us refer to
Mariner Energy, Inc. and its subsidiaries collectively. Certain
oil and natural gas industry terms used in this prospectus are
defined in the Glossary of Oil and Natural Gas Terms
beginning on page 171. References to pro forma
and on a pro forma basis mean on a pro forma basis,
giving effect to our merger with Forest Energy Resources, Inc.
which was completed on March 2, 2006, as if this merger had
occurred on the applicable date of determination or on the first
day of the applicable period. The unaudited pro forma
information contained in this prospectus has been derived from
and should be read together with the historical consolidated
financial statements of Mariner and the statements of revenues
and direct operating expenses of the Forest Gulf of Mexico
operations. The statements of revenues and direct operating
expenses of the Forest Gulf of Mexico operations do not include
all of the costs of doing business. The pro forma information is
for illustrative purposes only. The financial results may have
been different had the Forest Gulf of Mexico operations been an
independent company and had the companies always been combined.
You should not rely on the pro forma financial information as
being the historical results that would have been achieved had
the merger occurred in the past or the future financial results
that Mariner will achieve after the merger.
Our
Company
Mariner Energy, Inc. is an independent oil and gas exploration,
development and production company with principal operations in
the Gulf of Mexico, both shelf and deepwater, and in West Texas.
Our management has significant expertise and a successful
operating track record in these areas. In the three-year period
ended December 31, 2005, we added approximately 280 Bcfe of
proved reserves and produced approximately 100 Bcfe, while
deploying approximately $475 million of capital on
acquisitions, exploration and development.
Our primary operating strategy is to generate high-quality
exploration and development projects, which enables us to add
value through the drill bit. Our expertise in project generation
also facilitates our participation in high-quality projects
generated by other operators. We will also pursue acquisitions
of producing assets that have the potential to provide
acceptable risk-adjusted rates of return and further reserve
additions through exploration, exploitation, and development
opportunities. We target a balanced exposure to development,
exploitation and exploration opportunities, both offshore and
onshore and seek to maintain a moderate risk profile.
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources, Inc., which we refer to as Forest
Energy Resources. As a result of this merger, we acquired the
Gulf of Mexico operations of Forest Oil Corporation (NYSE: FST),
which we refer to as the Forest Gulf of Mexico operations. We
refer to Forest Oil Corporation as Forest.
As of December 31, 2005, we had 338 Bcfe of estimated
proved reserves, of which approximately 62% were natural gas and
38% were oil and condensate, and 50% of which was proved
developed. Pro forma for the merger transaction, as of
December 31, 2005, we had 644 Bcfe of estimated proved
reserves, of which approximately 68% were natural gas and 32%
were oil and condensate, and 56% of which was proved developed.
Our pro forma production for 2005 was approximately
95 Bcfe, or 260 MMcfe per day on average. During the
year ended December 31, 2005, our pro forma EBITDA was
approximately $438.6 million, including $25.7 million
of non-cash compensation expense related to restricted stock and
stock options granted in 2005, but excluding general and
administrative expenses of the Forest Gulf of Mexico operations.
Our production for the six months ended June 30, 2006 was
approximately 32 Bcfe, or 176 MMcfe per day on
average, and pro forma for the merger, 40 Bcfe, or
219 MMcfe per day on average. During the six months ended
June 30, 2006, our EBITDA was approximately
$190.6 million, and pro forma for the merger,
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approximately $241.6 million, in each case, including
$7.9 million of non-cash compensation expense related to
restricted stock and stock options. We believe the overhead
costs associated with the Forest Gulf of Mexico operations in
2006 will be approximately $6.4 million, net of capitalized
amounts. See footnote 1 on page 15 for our definition
of EBITDA and a reconciliation of net income to EBITDA.
The following table sets forth certain information with respect
to our estimated proved reserves, production and acreage by
geographic area on a pro forma basis for our merger with Forest
Energy Resources as of December 31, 2005. Reserve volumes
and values were determined under the method prescribed by the
SEC which requires the application of period-end prices and
costs held constant throughout the projected reserve life.
Proved reserve estimates do not include any value for probable
or possible reserves which may exist, nor do they include any
value for undeveloped acreage. The proved reserve estimates
represent our net revenue interest in our properties. The
reserve information for Mariner as of December 31, 2005 is
based on estimates made in a reserve report prepared by Ryder
Scott Company, L.P., independent petroleum engineers
(Ryder Scott). The reserve information as of
December 31, 2005 for the Forest Gulf of Mexico operations
is based on estimates made by internal staff engineers of
Forest, which estimates were audited by Ryder Scott.
Accordingly, the pro forma reserve information presented below
includes both reserves that were estimated by Ryder Scott and
reserves that were estimated by internal staff engineers of
Forest and audited by Ryder Scott. This information is presented
on a pro forma basis, giving effect to our merger with Forest
Energy Resources as though it had been consummated on
December 31, 2005. We consummated the merger on
March 2, 2006.
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Pro Forma
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Production for
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Year Ended
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Pro Forma
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December 31,
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Estimated Proved
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2005
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Reserve Quantities
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Pro Forma
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(Natural
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Oil
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Natural
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Total
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Total Net
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Gas
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Geographic Area
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(MMbbls)
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Gas (Bcf)
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(Bcfe)
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Acreage
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Equivalent (Bcfe))
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West Texas
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16.7
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105.5
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205.5
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31,199
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6.6
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Gulf of Mexico Deepwater(1)
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4.8
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95.7
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124.5
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241,320
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14.0
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Gulf of Mexico Shelf(2)
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12.7
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237.6
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313.7
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652,086
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74.3
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Total
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34.2
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438.8
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643.7
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924,605
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94.9
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Proved Developed Reserves
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18.4
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252.1
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362.3
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(1) |
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Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service). |
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Shelf refers to water depths less than 1,300 feet and
includes an insignificant amount of Gulf Coast onshore
properties. |
Our
Strategy and Our Competitive Strengths
Our
Strategy
The principal elements of our operating strategy include:
Generating and pursuing high-quality
prospects. We expect to continue our strategy of
growth through the drill bit by continuing to identify and
develop high-impact shelf, deep shelf and deepwater projects in
the Gulf of Mexico. Our technical team has significant expertise
in, and a successful track record of achieving growth by,
generating prospects internally and selectively participating in
prospects generated by other operators. We believe the Gulf of
Mexico is an area that offers substantial growth opportunities,
and our acquisition of the Forest Gulf of Mexico operations has
more than doubled our existing undeveloped acreage position in
the Gulf, providing numerous additional exploration,
exploitation and development opportunities.
Maintaining a moderate risk profile. We seek
to manage our risk profile by targeting a balanced exposure to
development, exploitation and exploration opportunities. For
example, we intend to continue
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to develop and seek to expand our West Texas asset base, which
contributes stable cash flows and long-lived reserves to our
portfolio as a counterbalance to our high-impact,
high-production Gulf of Mexico assets. We also seek to mitigate
and diversify our risk in drilling projects by selling partial
or entire interests in projects to industry partners or by
entering into arrangements with industry partners in which they
agree to pay a disproportionate share of drilling costs and
compensate us for expenses incurred in prospect generation. We
also enter into trades or farm-in transactions whereby we
acquire interests in third-party generated prospects, thereby
gaining exposure to a greater number of prospects. We expect
more opportunities to participate in these prospects in the
future as a result of our larger scale and increased cash flow
from the Forest Gulf of Mexico operations.
Pursuing opportunistic acquisitions. Until
2005, we grew our reserves primarily through the drill bit. In
2005 we added significant proved reserves primarily through
acquisitions in West Texas and subsequently in March 2006,
through the acquisition of the Forest Gulf of Mexico operations.
As part of our growth strategy, we will seek to continue to
acquire producing assets that have the potential to provide
acceptable risk-adjusted rates of return and further reserve
additions through exploration, exploitation and development
opportunities.
Our
Competitive Strengths
We believe our core resources and strengths include:
Our high-quality assets with geographic and geological
diversity. Our assets and operations are
diversified among the Gulf of Mexico shelf, deep shelf and
deepwater, and West Texas. Our asset portfolio provides a
balanced exposure to long-lived West Texas reserves, Gulf of
Mexico shelf growth opportunities and high-impact deepwater
prospects.
Our large inventory of prospects. We believe
we have significant potential for growth through the development
of our existing asset base. The acquisition of the Forest Gulf
of Mexico operations more than doubled our existing undeveloped
acreage position in the Gulf of Mexico to approximately
450,000 net acres and increased our total net leasehold
acreage offshore to nearly one million acres, providing numerous
exploration, exploitation and development opportunities. As of
September 30, 2006, we have an inventory of approximately
890 drilling locations in West Texas, which we believe
would require approximately six years to drill at our current
rate. These include approximately 430 locations pertaining
to 98 Bcfe of estimated net proved undeveloped reserves and
approximately 460 other locations.
Our successful track record of finding and developing oil and
gas reserves. We have demonstrated our expertise
in finding and developing additional proved reserves. In the
three-year period ended December 31, 2005, we deployed
approximately $475 million of capital on acquisitions,
exploration and development, while adding approximately
280 Bcfe of proved reserves and producing approximately
100 Bcfe.
Our depth of operating experience. Our team of
41 geoscientists, engineers, geologists and other technical
professionals and landmen as of September 30, 2006 average
more than 22 years of experience in the exploration and
production business (including extensive experience in the Gulf
of Mexico), much of it with major oil companies. The addition of
experienced Forest personnel to Mariners team of technical
professionals has further enhanced our ability to generate and
maintain an inventory of high-quality drillable prospects and to
further develop and exploit our assets. Mariners technical
team has also proven to be an effective and efficient operator
in West Texas, as evidenced by our successful production and
reserve growth there in recent years.
Our technology and production techniques. Our
team of geoscientists currently has access to seismic data from
multiple, recent
vintage 3-D
seismic databases covering more than 7,000 blocks in the Gulf of
Mexico that we intend to continue to use to develop prospects on
acreage being evaluated for leasing and to develop and further
refine prospects on our expanded acreage position. We also have
extensive experience and a successful track record in the use of
subsea tieback technology to connect
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offshore wells to existing production facilities. This
technology facilitates production from offshore properties
without the necessity of fabrication and installation of
platforms and top-side facilities that typically are more costly
and require longer lead times. We believe the use of subsea
tiebacks in appropriate projects enables us to bring production
online more quickly, makes target prospects more profitable and
allows us to exploit reserves that may otherwise be considered
non-commercial because of the high cost of infrastructure. In
the Gulf of Mexico, in the three years ended December 31,
2005, we were directly involved in 14 projects (five of which we
operated) utilizing subsea tieback systems in water depths
ranging from 475 feet to more than 6,700 feet. As of
September 30, 2006, we had 18 subsea wells in water depths
ranging from 450 feet to more than 4,700 feet. These
wells were tied back to 13 host production facilities for
production processing. An additional nine wells in water depths
ranging from 465 feet to more than 6,800 feet were
then under development for tieback to five additional host
production facilities.
Recent
Developments
Forest
Gulf of Mexico Merger
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources. Prior to the consummation of the
merger, Forest transferred and contributed the assets and
certain liabilities associated with its Gulf of Mexico
operations to Forest Energy Resources. Immediately prior to the
merger, Forest distributed all of the outstanding shares of
Forest Energy Resources to Forest shareholders on a pro rata
basis. Forest Energy Resources then merged with a newly-formed
subsidiary of Mariner, became a new wholly-owned subsidiary of
Mariner and changed its name to Mariner Energy Resources, Inc.
Immediately following the merger, approximately 59% of Mariner
common stock was held by shareholders of Forest and
approximately 41% of Mariner common stock was held by the
pre-merger stockholders of Mariner.
Forest Energy Resources had approximately 306 Bcfe of
estimated proved reserves as of December 31, 2005, of which
approximately 76% were natural gas, and 24% were oil and
condensate. The reserves and operations acquired from Forest are
concentrated in the shelf and deep shelf of the Gulf of Mexico
and represent a significant addition to Mariners asset
portfolio in those areas of operation.
We believe our acquisition of the Forest Gulf of Mexico
operations and the scale they bring to our business has further
moderated our risk profile, provided many exploration,
exploitation and development opportunities, enhanced our ability
to participate in prospects generated by other operators, and
added a significant cash flow generating resource that has
improved our ability to compete effectively in the Gulf of
Mexico and fund exploration activities and acquisitions. We
believe we are well-positioned to optimize the Forest Energy
Resources assets through aggressive and timely exploitation.
West
Cameron Acquisition
In August 2006, we acquired the interest of BP Exploration and
Production Inc., which we refer to as BP, in West
Cameron Block 110 and the southeast quarter of West Cameron
Block 111 in the Gulf of Mexico. The interest was acquired
by our subsidiary, Mariner Energy Resources, Inc., exercising
its preferential right to purchase. BP retained its interest in
depths below 15,000 feet. In the Forest merger, we acquired
Forest Energy Resources 37.5% interest in the properties.
As a result of the August 2006 acquisition, Mariner Energy
Resources, Inc. now owns 100% of the working interest, exclusive
of the deep rights retained by BP, and Mariner Energy, Inc.
became operator of the interests owned by its subsidiary. The
acquisition cost, net of preliminary purchase price adjustments,
was approximately $70.9 million, which was financed by
borrowing under our senior secured credit facility. A
$10.4 million letter of credit under our senior secured
credit facility also was issued in favor of BP to secure
plugging and abandonment obligations. The acquisition adds
proved reserves estimated by us to be 20 Bcfe as of
August 1, 2006. Production associated with the acquired
interest was approximately 11 MMcfe/day during July 2006.
4
Material
Gulf of Mexico Discovery
In October 2006, we announced that we made a material
conventional shelf discovery in the High Island
116 #5ST1 well, drilled to a total measured depth of
14,683 feet / 13,150 feet true vertical depth. The
well encountered approximately 540 feet of net true
vertical depth pay in thirteen sands. We anticipate completion
and initial production in the fourth quarter of 2006. High
Island 116 is part of the Forest Gulf of Mexico operations we
acquired in March 2006. We have a 100% working interest and an
approximate 72% net revenue interest in the well.
Effects
of the 2005 Hurricane Season
In 2005, our operations were adversely affected by one of the
most active and severe hurricane seasons in recorded history,
resulting in shut-in production and startup delays. We estimate
that as of September 30, 2006, approximately 12 MMcfe
per day of production remained shut-in and approximately
33 MMcfe per day of production had recommenced since
June 30, 2006. The four deepwater projects that experienced
startup delays have recommenced production. As a result of
ongoing repairs to pipelines, facilities, terminals and host
facilities, we expect most of the remaining shut-in production
to recommence by the end of 2006 and the balance in 2007, except
that an immaterial amount of production is not expected to
recommence.
We estimate the costs to repair damage caused by the hurricanes
to our platforms and facilities will be approximately
$80 million. However, until we are able to complete all the
repair work this estimate is subject to significant variance.
For the insurance period covering the 2005 hurricane activity,
we carried a $3 million annual deductible and a
$0.5 million single occurrence deductible for the Mariner
assets. Insurance covering the Forest Gulf of Mexico properties
carried a $5 million deductible for each occurrence. Until
the repairs are completed and we submit costs to our insurance
underwriters for review, the full extent of our insurance
recoveries and the resulting net cost to us for Hurricanes
Katrina and Rita will be unknown. However, we expect the total
costs not covered by the combined insurance policies to be less
than $15 million.
Corporate
Information
We were incorporated in August 1983 as a Delaware corporation.
We have three subsidiaries, Mariner Energy Resources, Inc., a
Delaware corporation, Mariner LP LLC, a Delaware limited
liability company, and Mariner Energy Texas LP, a Delaware
limited partnership. Our principal executive office is located
at One Briar Lake Plaza, Suite 2000, 2000 West Sam
Houston Parkway South, Houston, Texas 77042. Our telephone
number is
(713) 954-5500.
5
The
Exchange Offer
On April 24, 2006, we completed an unregistered offering of
the old notes. As part of that offering, we entered into a
registration rights agreement with the initial purchasers of the
old notes in which we agreed, among other things, to deliver
this prospectus to you and to use commercially reasonable
efforts to complete the exchange offer. We refer to the old
notes and the new notes (separately or collectively, as the
context indicates) as the notes. The following is a
summary of the exchange offer.
|
|
|
Old Notes |
|
71/2% Senior
Notes due April 15, 2013, which were issued on
April 24, 2006. |
|
New Notes |
|
71/2% Senior
Notes due April 15, 2013. The terms of the new notes are
substantially identical to those terms of the old notes, except
that the transfer restrictions, registration rights and special
interest provisions relating to the old notes do not apply to
the new notes. |
|
Exchange Offer |
|
We are offering to exchange $300.0 million principal amount
of our new notes that have been registered under the Securities
Act for an equal amount of our old notes to satisfy our
obligations under the registration rights agreement. |
|
|
|
The new notes will evidence the same debt as the old notes and
will be issued under and be entitled to the benefits of the same
indenture that governs the old notes. Holders of the old notes
do not have any appraisal or dissenters rights in
connection with the exchange offer. Because the new notes will
be registered, the new notes will not be subject to transfer
restrictions, and holders of old notes that have tendered and
had their old notes accepted in the exchange offer will have no
registration rights. |
|
Expiration Date |
|
The exchange offer will expire at 5:00 P.M., New York City
time, on November 9, 2006, unless we decide to extend it.
We do not currently intend to extend the exchange offer. A
tender of old notes pursuant to this exchange offer may be
withdrawn at any time prior to the expiration date. Any old
notes not accepted for exchange for any reason will be returned
without expense to the tendering holder promptly after the
expiration or termination of this exchange offer. |
|
Conditions to the Exchange Offer |
|
The exchange offer is subject to customary conditions, which we
may, but are not required to, waive. Please see The
Exchange Offer Conditions to the Exchange
Offer for more information regarding the conditions to the
exchange offer. |
|
Procedures for Tendering Old Notes |
|
Unless you comply with the procedures described below under
The Exchange Offer Procedures for Tendering
Old Notes Guaranteed Delivery, you must do one
of the following on or prior to the expiration of the exchange
offer to participate in the exchange offer: |
|
|
|
tender your old notes by sending the certificates
for your old notes, in proper form for transfer, a properly
completed and duly executed letter of transmittal with the
required signature guarantee, and all other documents required
by the letter of transmittal, to Wells Fargo Bank, N.A., as
registrar and exchange agent, at the address set forth in this
prospectus; or
|
|
|
|
tender your old notes by using the book-entry
transfer procedures described in The Exchange
Offer Procedures for Tendering |
6
|
|
|
|
|
Old Notes Book-Entry Delivery Procedures and
transmitting a properly completed and duly executed letter of
transmittal with the required signature guarantee, or an
agents message instead of the letter of transmittal, to
the exchange agent. In order for a book-entry transfer to
constitute a valid tender of your old notes in the exchange
offer, Wells Fargo Bank, N.A., as registrar and exchange agent,
must receive a confirmation of book-entry transfer of your old
notes into the exchange agents account at The Depository
Trust Company prior to the expiration of the exchange offer. |
|
|
|
By signing or agreeing to be bound by the letter of transmittal,
you will represent to us that, among other things: |
|
|
|
any new notes that you will receive will be acquired
in the ordinary course of your business;
|
|
|
|
you have no arrangement or understanding with any
person or entity to participate in the distribution of the new
notes; |
|
|
|
if you are a broker-dealer that will receive new
notes for your own account in exchange for old notes that were
acquired as a result of market-making activities, that you will
deliver a prospectus, as required by law, in connection with any
resale of such new notes; and |
|
|
|
you are not our or any guarantors
affiliate as defined in Rule 405 under the
Securities Act. |
|
Guaranteed Delivery Procedures |
|
If you wish to tender your old notes in the exchange offer, but
they are not immediately available or if you cannot deliver your
old notes and the other required documents prior to the
expiration date, then you may tender old notes by following the
procedures described below under The Exchange
Offer Procedures for Tendering Old Notes
Guaranteed Delivery. |
|
Special Procedures for Beneficial Owners |
|
If you are a beneficial owner whose old notes are registered in
the name of a broker, dealer, commercial bank, trust company or
other nominee and you wish to tender your old notes in the
exchange offer, you should promptly contact the person in whose
name the old notes are registered and instruct that person to
tender on your behalf. |
|
|
|
If you wish to tender in the exchange offer on your own behalf,
prior to completing and executing the letter of transmittal and
delivering the certificates for your old notes, you must either
make appropriate arrangements to register ownership of the old
notes in your name or obtain a properly completed bond power
from the person in whose name the old notes are registered. |
|
Withdrawal; Non-Acceptance |
|
You may withdraw any old notes tendered in the exchange offer at
any time prior to 5:00 P.M., New York City time, on
November 9, 2006. If we decide for any reason not to accept
any old notes tendered for exchange, the old notes will be
returned to the registered holder at our expense promptly after
the expiration or termination of the exchange offer. In the case
of old notes tendered |
7
|
|
|
|
|
by book-entry transfer into the exchange agents account at
The Depository Trust Company, any withdrawn or unaccepted old
notes will be credited to the tendering holders account at
The Depository Trust Company. For further information regarding
the withdrawal of tendered old notes, please see The
Exchange Offer Withdrawal of Tenders. |
|
United States Federal Income Tax Considerations |
|
The exchange of new notes for old notes in the exchange offer
will not be a taxable event for United States federal income tax
purposes. Please see Material United States Federal Income
Tax Considerations for more information regarding the tax
consequences to you of the exchange offer. |
|
Use of Proceeds |
|
The issuance of the new notes will not provide us with any new
proceeds. We are making this exchange offer solely to satisfy
our obligations under the registration rights agreement. |
|
Fees and Expenses |
|
We will pay all of our expenses incident to the exchange offer. |
|
Exchange Agent |
|
We have appointed Wells Fargo Bank, N.A. as exchange agent for
the exchange offer. You can find the address and telephone
number of the exchange agent under The Exchange
Offer Exchange Agent. |
|
Resales of New Notes |
|
Based on interpretations by the staff of the Securities and
Exchange Commission, as set forth in no-action letters issued to
third parties, we believe that the new notes you receive in the
exchange offer may be offered for resale, resold or otherwise
transferred by you without compliance with the registration and
prospectus delivery provisions of the Securities Act so long as
certain conditions are met. See The Exchange
Offer Resale of the New Notes; Plan of
Distribution for more information regarding resales. |
|
Consequences of Not Exchanging Your Old Notes |
|
If you do not exchange your old notes in this exchange offer,
you will no longer be able to require us to register your old
notes under the Securities Act except in the limited
circumstances provided under the registration rights agreement.
In addition, you will not be able to resell, offer to resell or
otherwise transfer your old notes unless we have registered the
old notes under the Securities Act, or unless you resell, offer
to resell or otherwise transfer them under an exemption from the
registration requirements of, or in a transaction not subject
to, the Securities Act and applicable state securities laws.
Other than in connection with this exchange offer, or as
otherwise required under certain limited circumstances pursuant
to the terms of the registration rights agreement, we do not
currently anticipate that we will register the old notes under
the Securities Act. |
|
|
|
For information regarding the consequences of not tendering your
old notes and our obligation to file a registration statement,
please see The Exchange Offer Consequences of
Failure to Exchange and Description of Senior
Notes. |
8
Description
of Senior Notes
The terms of the new notes and those of the outstanding old
notes are substantially identical, except that the transfer
restrictions and registration rights relating to the old notes
do not apply to the new notes. As a result, the new notes will
not bear legends restricting their transfer and will not have
the benefit of the registration rights and related special
interest provisions contained in the old notes. The new notes
represent the same debt as the old notes for which they are
being exchanged. Both the old notes and the new notes are
governed by the same indenture.
|
|
|
Issuer |
|
Mariner Energy, Inc. |
|
Notes Offered |
|
$300,000,000 principal amount of its
71/2% Senior
Notes due 2013. |
|
Maturity Date |
|
April 15, 2013. |
|
Interest Rate |
|
71/2% per
year (calculated using a
360-day
year). |
|
Interest Payment Dates |
|
Each April 15 and October 15, beginning October 15,
2006. |
|
Ranking |
|
The notes are our general unsecured senior obligations.
Accordingly, they rank: |
|
|
|
effectively subordinate to all of our existing and
future secured indebtedness, including indebtedness under our
credit facility, to the extent of the collateral securing such
indebtedness; |
|
|
|
effectively subordinate to all existing and future
indebtedness and other liabilities of any non-guarantor
subsidiaries (other than indebtedness and liabilities owed to
us); |
|
|
|
pari passu in right of payment to all of our
existing and future senior unsecured indebtedness; and |
|
|
|
senior in right of payment to any future
subordinated indebtedness. |
|
|
|
As of June 30, 2006, we had total indebtedness of
approximately $457 million, $300 million of which was
the notes, and approximately $157 million of which was
secured indebtedness to which the notes effectively were
subordinated as to the value of the collateral. We also then had
two letters of credit outstanding for $40.0 million and
$4.2 million, each of which effectively was senior to the
notes to the extent of the collateral securing such indebtedness. |
|
Subsidiary Guarantees |
|
The notes are jointly and severally guaranteed on a senior
unsecured basis by our existing and future domestic
subsidiaries. In the future, the guarantees may be released or
terminated under certain circumstances. Each subsidiary
guarantee ranks: |
|
|
|
effectively subordinate to all existing and future
secured indebtedness of the guarantor subsidiary, including its
guarantee of indebtedness under our credit facility, to the
extent of the collateral securing such indebtedness; |
|
|
|
pari passu in right of payment to all existing and
future senior unsecured indebtedness of the guarantor
subsidiary; and |
|
|
|
senior in right of payment to any future
subordinated indebtedness of the guarantor subsidiary. |
9
|
|
|
|
|
As of June 30, 2006, the guarantor subsidiary Mariner
Energy Resources, Inc. had approximately $157 million of
senior secured indebtedness outstanding, and approximately
$19.2 million of unsecured indebtedness outstanding under
an intercompany note payable to us. The other two guarantor
subsidiaries were guarantors but not indebted under our senior
secured credit facility and had no other indebtedness
outstanding. |
|
Optional Redemption |
|
At any time prior to April 15, 2009, we may redeem up to
35% of each of the notes with the net cash proceeds of certain
equity offerings at the redemption prices set forth under
Description of Senior Notes Optional
Redemption, if at least 65% of the aggregate principal
amount of the notes issued under the indenture remains
outstanding immediately after such redemption and the redemption
occurs within 180 days of the closing date of such equity
offering. |
|
|
|
At any time prior to April 15, 2010, we may redeem the
notes, in whole or in part, at a make whole
redemption price set forth under Description of Senior
Notes Optional Redemption. On and after
April 15, 2010, we may redeem the notes, in whole or in
part, at the redemption prices set forth under Description
of Senior Notes Optional Redemption. |
|
Change of Control Triggering Event |
|
If a Change of Control Triggering Event occurs, we must offer to
repurchase the notes at the redemption price set forth under
Description of Senior Notes Repurchase at the
Option of Holders Change of Control. |
|
Certain Covenants |
|
The indenture governing the notes contains covenants that, among
other things, limit our ability and the ability of our
restricted subsidiaries to: |
|
|
|
make investments; |
|
|
|
incur additional indebtedness or issue preferred
stock; |
|
|
|
create certain liens; |
|
|
|
sell assets; |
|
|
|
enter into agreements that restrict dividends or
other payments from our subsidiaries to us; |
|
|
|
consolidate, merge or transfer all or substantially
all of the assets of our company; |
|
|
|
engage in transactions with affiliates; |
|
|
|
pay dividends or make other distributions on capital
stock or subordinated indebtedness; and |
|
|
|
create unrestricted subsidiaries. |
|
|
|
These covenants are subject to important exceptions and
qualifications. In addition, substantially all of the covenants
will terminate before the notes mature if one of two specified
ratings agencies assigns the notes an investment grade rating in
the future and no events of default exist under the indentures.
Any covenants that cease to apply to us as a result of achieving
an investment |
10
|
|
|
|
|
grade rating will not be restored, even if the credit rating
assigned to the notes later falls below an investment grade
rating. See Description of Senior Notes
Certain Covenants. |
|
Absence of Established Market for the Notes |
|
The new notes are generally freely transferable but are also new
securities for which there will not initially be a market.
Accordingly, we cannot assure you as to the development or
liquidity of any market for the new notes. The notes will be
eligible for trading in the
PORTALsm
Market. We do not intend to apply for a listing of the new notes
on any securities exchange or for the inclusion on any automated
dealer quotation system. |
|
Use of Proceeds |
|
We will not receive any proceeds from the exchange offer. |
11
Summary
Historical Financial Information
The following table shows Mariners summary historical
consolidated financial data as of and for the six months ended
June 30, 2006 and June 30, 2005, the year ended
December 31, 2005, the period from January 1, 2004
through March 2, 2004, the period from March 3, 2004
through December 31, 2004, and each of the three years
ended December 31, 2003. The summary historical
consolidated financial data for the year ended December 31,
2005, the period from January 1, 2004 through March 2,
2004, the period from March 3, 2004 through
December 31, 2004, and each of the three years ended
December 31, 2003 are derived from Mariners audited
financial statements included herein, and the historical
consolidated financial data as of and for the two years ended
December 31, 2002 are derived from Mariners audited
financial statements that are not included herein. The summary
historical consolidated financial data for the six months ended
June 30, 2006 and the six months ended June 30, 2005
has been derived from Mariners unaudited financial
statements. You should read the following data in connection
with Managements Discussion and Analysis of
Financial Condition and Results of Operations, and the
consolidated financial statements included elsewhere in this
prospectus, where there is additional disclosure regarding the
information in the following table, including pro forma
information regarding the merger with Forest Energy Resources.
Mariners historical results are not necessarily indicative
of results to be expected in future periods.
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
the financial information as of June 30, 2006 below
includes the Forest Gulf of Mexico operations as of and after
March 2, 2006.
On March 2, 2004, Mariners former indirect parent,
Mariner Energy LLC, merged with MEI Acquisitions, LLC, an
affiliate of the private equity funds, Carlyle/Riverstone Global
Energy and Power Fund II, L.P. and ACON Investments LLC.
The financial information contained herein is presented in the
style of Post-2004 Merger activity (for the March 3, 2004
through December 31, 2004 period, the year ended
December 31, 2005 and the six months ended June 30,
2006 and June 30, 2005) and Pre-2004 Merger activity
(for all periods prior to March 2, 2004) to
reflect the impact of the restatement of assets and liabilities
to fair value as required by push-down purchase
accounting at the March 2, 2004 merger date.
12
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(1)
|
|
$
|
247.9
|
|
|
$
|
107.6
|
|
|
$
|
199.7
|
|
|
$
|
174.4
|
|
|
|
$
|
39.8
|
|
|
$
|
142.5
|
|
|
$
|
158.2
|
|
|
$
|
155.0
|
|
Lease operating expenses
|
|
|
37.6
|
|
|
|
13.2
|
|
|
|
29.9
|
|
|
|
21.4
|
|
|
|
|
4.1
|
|
|
|
24.7
|
|
|
|
26.1
|
|
|
|
20.1
|
|
Transportation expenses
|
|
|
2.3
|
|
|
|
1.5
|
|
|
|
2.3
|
|
|
|
1.9
|
|
|
|
|
1.1
|
|
|
|
6.3
|
|
|
|
10.5
|
|
|
|
12.0
|
|
Depreciation, depletion and
amortization
|
|
|
109.8
|
|
|
|
31.1
|
|
|
|
59.4
|
|
|
|
54.3
|
|
|
|
|
10.6
|
|
|
|
48.3
|
|
|
|
70.8
|
|
|
|
63.5
|
|
Impairment of production equipment
held for use
|
|
|
|
|
|
|
|
|
|
|
1.8
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
Impairment of Enron related
receivables
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
29.5
|
|
General and administrative expenses
|
|
|
17.4
|
|
|
|
15.4
|
|
|
|
37.1
|
|
|
|
7.6
|
|
|
|
|
1.1
|
|
|
|
8.1
|
|
|
|
7.7
|
|
|
|
9.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
80.8
|
|
|
|
46.4
|
|
|
|
69.2
|
|
|
|
88.2
|
|
|
|
|
22.9
|
|
|
|
51.9
|
|
|
|
39.9
|
|
|
|
20.6
|
|
Interest income
|
|
|
0.3
|
|
|
|
0.6
|
|
|
|
0.8
|
|
|
|
0.2
|
|
|
|
|
0.1
|
|
|
|
0.8
|
|
|
|
0.4
|
|
|
|
0.7
|
|
Interest expense
|
|
|
(14.7
|
)
|
|
|
(3.6
|
)
|
|
|
(8.2
|
)
|
|
|
(6.0
|
)
|
|
|
|
|
|
|
|
(7.0
|
)
|
|
|
(10.3
|
)
|
|
|
(8.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
66.4
|
|
|
|
43.4
|
|
|
|
61.8
|
|
|
|
82.4
|
|
|
|
|
23.0
|
|
|
|
45.7
|
|
|
|
30.0
|
|
|
|
12.4
|
|
Provision for income taxes
|
|
|
(24.6
|
)
|
|
|
(14.8
|
)
|
|
|
(21.3
|
)
|
|
|
(28.8
|
)
|
|
|
|
(8.1
|
)
|
|
|
(9.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method net of tax effects
|
|
$
|
41.8
|
|
|
$
|
28.6
|
|
|
|
40.5
|
|
|
|
53.6
|
|
|
|
|
14.9
|
|
|
|
36.3
|
|
|
|
30.0
|
|
|
|
12.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect
per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.62
|
|
|
$
|
0.90
|
|
|
|
1.24
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.22
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Diluted
|
|
|
0.62
|
|
|
|
0.89
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.22
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Cumulative effect of changes in
accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
41.8
|
|
|
$
|
28.6
|
|
|
$
|
40.5
|
|
|
$
|
53.6
|
|
|
|
$
|
14.9
|
|
|
$
|
38.2
|
|
|
$
|
30.0
|
|
|
$
|
12.4
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.62
|
|
|
$
|
0.90
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
0.50
|
|
|
$
|
1.29
|
|
|
$
|
1.01
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
0.62
|
|
|
|
0.89
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.29
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Capital Expenditure and
Disposal Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, including
leasehold/seismic
|
|
|
138.7
|
|
|
|
7.5
|
|
|
$
|
60.9
|
|
|
$
|
40.4
|
|
|
|
$
|
7.5
|
|
|
$
|
31.6
|
|
|
$
|
40.4
|
|
|
$
|
66.3
|
|
Development and other
|
|
|
134.2
|
|
|
|
72.0
|
|
|
|
191.8
|
|
|
|
93.2
|
|
|
|
|
7.8
|
|
|
|
51.7
|
|
|
|
65.7
|
|
|
|
98.2
|
|
Proceeds from property conveyances
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6
|
)
|
|
|
(52.3
|
)
|
|
|
(90.5
|
)
|
Total capital expenditures net of
proceeds from property conveyances
|
|
|
270.9
|
|
|
|
79.5
|
|
|
$
|
252.7
|
|
|
$
|
133.6
|
|
|
|
$
|
15.3
|
|
|
$
|
(38.3
|
)
|
|
$
|
53.8
|
|
|
$
|
74.0
|
|
|
|
|
(1) |
|
Includes effects of hedging. |
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions)
|
|
Balance Sheet
Data(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net, full
cost method
|
|
$
|
1,913.6
|
|
|
$
|
351.3
|
|
|
$
|
515.9
|
|
|
$
|
303.8
|
|
|
|
$
|
207.9
|
|
|
$
|
287.6
|
|
|
$
|
290.6
|
|
Total assets
|
|
|
2,457.1
|
|
|
|
463.1
|
|
|
|
665.5
|
|
|
|
376.0
|
|
|
|
|
312.1
|
|
|
|
360.2
|
|
|
|
363.9
|
|
Long-term debt, less current
maturities
|
|
|
457.0
|
|
|
|
99.0
|
|
|
|
156.0
|
|
|
|
115.0
|
|
|
|
|
|
|
|
|
99.8
|
|
|
|
99.8
|
|
Stockholders equity
|
|
|
1,184.2
|
|
|
|
201.0
|
|
|
|
213.3
|
|
|
|
133.9
|
|
|
|
|
218.2
|
|
|
|
170.1
|
|
|
|
180.1
|
|
Working capital (deficit)(2)
|
|
|
(100.8
|
)
|
|
|
18.3
|
|
|
|
(46.4
|
)
|
|
|
(18.7
|
)
|
|
|
|
38.3
|
|
|
|
(24.4
|
)
|
|
|
(19.6
|
)
|
Other Financial
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratio of earnings to fixed
charges(3)
|
|
|
5.25
|
|
|
|
12.54
|
|
|
|
7.88
|
|
|
|
17.17
|
|
|
|
|
6.83
|
|
|
|
3.56
|
|
|
|
1.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Balance sheet data as of June 30, 2006 reflects
consolidation of the assets of the Forest Gulf of Mexico
operations effective March 2, 2006. Balance sheet data as
of December 31, 2004 reflects purchase accounting
adjustments to oil and gas properties, total assets and
stockholders equity resulting from the acquisition of our
former indirect parent on March 2, 2004. |
|
(2) |
|
Working capital (deficit) excludes current derivative assets and
liabilities, deferred tax assets and restricted cash. |
|
(3) |
|
For the purposes of determining the ratio of earnings to fixed
charges, earnings consist of income before taxes, plus fixed
charges, less capitalized interest, and fixed charges consist of
interest expense (net of capitalized interest), plus capitalized
interest, plus amortized discounts related to indebtedness. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions)
|
|
Other Financial
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
190.6
|
|
|
$
|
77.5
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Net cash provided by operating
activities
|
|
|
96.1
|
|
|
|
72.7
|
|
|
|
165.4
|
|
|
|
135.2
|
|
|
|
|
20.3
|
|
|
|
88.9
|
|
|
|
60.3
|
|
|
|
113.5
|
|
Net cash (used) provided by
investing activities
|
|
|
(204.8
|
)
|
|
|
(98.7
|
)
|
|
|
(247.8
|
)
|
|
|
(133.0
|
)
|
|
|
|
(15.3
|
)
|
|
|
52.9
|
|
|
|
(53.8
|
)
|
|
|
(74.0
|
)
|
Net cash (used) provided by
financing activities
|
|
|
109.8
|
|
|
|
31.5
|
|
|
|
84.4
|
|
|
|
64.9
|
|
|
|
|
|
|
|
|
(100.0
|
)
|
|
|
|
|
|
|
(30.0
|
)
|
Reconciliation of
Non-GAAP Measures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
190.6
|
|
|
$
|
77.5
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Changes in working capital
|
|
|
(93.6
|
)
|
|
|
(14.9
|
)
|
|
|
20.0
|
|
|
|
6.2
|
|
|
|
|
(13.2
|
)
|
|
|
7.2
|
|
|
|
(20.4
|
)
|
|
|
7.5
|
|
Non-cash hedge loss(2)
|
|
|
(3.5
|
)
|
|
|
(2.5
|
)
|
|
|
(4.5
|
)
|
|
|
(7.9
|
)
|
|
|
|
|
|
|
|
(2.0
|
)
|
|
|
(23.2
|
)
|
|
|
|
|
Amortization/other
|
|
|
9.1
|
|
|
|
6.1
|
|
|
|
1.2
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
0.6
|
|
Stock compensation expense
|
|
|
7.9
|
|
|
|
9.5
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(14.4
|
)
|
|
|
(3.0
|
)
|
|
|
(7.4
|
)
|
|
|
(5.8
|
)
|
|
|
|
0.1
|
|
|
|
(6.2
|
)
|
|
|
(9.9
|
)
|
|
|
(8.2
|
)
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.6
|
)
|
|
|
|
|
|
|
|
(10.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
$
|
96.1
|
|
|
$
|
72.7
|
|
|
$
|
165.4
|
|
|
$
|
135.2
|
|
|
|
$
|
20.3
|
|
|
$
|
88.9
|
|
|
$
|
60.3
|
|
|
$
|
113.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
(1) |
|
EBITDA means earnings before interest, income taxes,
depreciation, depletion and amortization and impairments. For
the six months ended June 30, 2006 and 2005, EBITDA
includes $7.9 million and $9.5 million, respectively,
in non-cash compensation expense related to restricted stock and
stock options. For the year ended December 31, 2005, EBITDA
includes $25.7 million in non-cash compensation expense
related to restricted stock and stock options granted in 2005.
We believe that EBITDA is a widely accepted financial indicator
that provides additional information about our ability to meet
our future requirements for debt service, capital expenditures
and working capital, but EBITDA should not be considered in
isolation or as a substitute for net income, operating income,
net cash provided by operating activities or any other measure
of financial performance presented in accordance with generally
accepted accounting principles or as a measure of a
companys profitability or liquidity. |
|
(2) |
|
In accordance with SFAS No. 133 Accounting for
Derivative Instruments and Hedging Activities, as amended
by SFAS No. 137 and No. 138, we de-designated our
contracts effective December 2, 2001 after the counterparty
(an affiliate of Enron Corp.) filed for bankruptcy and
recognized all market value changes subsequent to such
de-designation in our earnings. The value recorded up to the
time of dedesignation and included in Accumulated Other
Comprehensive Income (AOCI), has reversed out of
AOCI and into earnings as the original corresponding production,
as hedged by the contracts, is produced. In accordance with
purchase price accounting implemented at the time of the merger
of our former indirect parent on March 2, 2004, we recorded
the mark to market liability of our hedge contracts at such date
totaling $12.4 million as a liability on our balance sheet.
The value at the time of the merger and included in AOCI has
reversed out of AOCI and into earnings as the original
corresponding production, as hedged by the contracts, is
produced. We have designated subsequent hedge contracts as cash
flow hedges with gains and losses resulting from the
transactions recorded at market value in AOCI, as appropriate,
until recognized as operating income in our Statement of
Operations as the physical production hedged by the contracts is
delivered. |
15
Summary
Selected Unaudited Pro Forma Combined Condensed Financial
Information
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
actual balance sheet information of the combined company as of
June 30, 2006 is included elsewhere in this prospectus.
The following unaudited pro forma combined condensed operating
results for the six months ended June 30, 2006 and the year
ended December 31, 2005 give effect to the merger as if it
had occurred on January 1, 2005. This unaudited pro forma
combined condensed financial information is based on the
historical financial statements of Mariner and the historical
statements of revenues and direct operating expenses of the
Forest Gulf of Mexico operations, all of which are included in
this prospectus, and the estimates and assumptions set forth in
the notes to the Unaudited Pro Forma Combined Condensed
Financial Information beginning on page 45.
The unaudited pro forma combined condensed financial information
is for illustrative purposes only. The financial results may
have been different had the Forest Gulf of Mexico operations
been an independent company and had the companies always been
combined. You should not rely on the unaudited pro forma
combined condensed financial information as being indicative of
the historical results that would have been achieved had the
merger occurred in the past or the future financial results that
Mariner will achieve after the merger.
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Year Ended
|
|
|
|
Ended
|
|
|
December 31,
|
|
|
|
June 30, 2006
|
|
|
2005
|
|
|
|
(In millions, except earnings per share and share data)
|
|
|
OPERATING RESULTS:
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
315.4
|
|
|
$
|
592.0
|
|
Net income
|
|
|
56.2
|
|
|
|
58.0
|
|
Earnings per share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.67
|
|
|
$
|
0.70
|
|
Diluted
|
|
$
|
0.66
|
|
|
$
|
0.69
|
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
84,277,028
|
|
|
|
83,304,592
|
|
Diluted
|
|
|
85,405,169
|
|
|
|
84,454,427
|
|
16
Summary
Reserve and Operating Data
The following tables present certain information with respect to
our estimated proved oil and natural gas reserves at year end
and operating data for the periods presented. The 2005
information is also presented on a pro forma basis, giving
effect to our merger with Forest Energy Resources as though it
had been consummated on January 1, 2005. We consummated the
merger on March 2, 2006.
Estimated
Proved Reserves
The reserve information in the table below for Mariner is based
on estimates made in reserve reports prepared by Ryder Scott.
The reserve information as of December 31, 2005 for the
Forest Gulf of Mexico operations is based on estimates made by
internal staff engineers at Forest, which estimates were audited
by Ryder Scott. Accordingly, the pro forma reserve information
presented below includes both reserves that were estimated by
Ryder Scott and reserves that were estimated by internal staff
engineers at Forest and audited by Ryder Scott.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
As of the Year Ended
|
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
|
December 31, 2005
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Estimated proved oil and
natural gas reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas reserves (Bcf)
|
|
|
438.8
|
|
|
|
207.7
|
|
|
|
151.9
|
|
|
|
127.6
|
|
Oil (MMbbls)
|
|
|
34.1
|
|
|
|
21.6
|
|
|
|
14.3
|
|
|
|
13.1
|
|
Total proved oil and natural gas
reserves (Bcfe)
|
|
|
643.7
|
|
|
|
337.6
|
|
|
|
237.5
|
|
|
|
206.1
|
|
Total proved developed reserves
(Bcfe)
|
|
|
362.3
|
|
|
|
167.4
|
|
|
|
109.4
|
|
|
|
96.6
|
|
PV10 value ($ in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
$
|
2,023.4
|
|
|
$
|
849.6
|
|
|
$
|
335.4
|
|
|
$
|
314.6
|
|
Proved undeveloped reserves
|
|
|
1,028.4
|
|
|
|
432.2
|
|
|
|
332.6
|
|
|
|
218.9
|
|
Total PV10 value
|
|
|
3,051.8
|
|
|
|
1,281.8
|
|
|
|
668.0
|
|
|
|
533.5
|
|
Standardized measure
|
|
|
2,201.7
|
|
|
|
906.6
|
|
|
|
494.4
|
|
|
|
418.2
|
|
Prices used in calculating end
of period proved reserve measures (excluding effects of
hedging)(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/MMBtu)
|
|
$
|
10.05
|
|
|
$
|
10.05
|
|
|
$
|
6.15
|
|
|
$
|
5.96
|
|
Oil ($/bbl)
|
|
|
61.04
|
|
|
|
61.04
|
|
|
|
43.45
|
|
|
|
32.52
|
|
|
|
|
(1) |
|
Our PV10 values have been calculated using NYMEX prices at the
end of the relevant period, as adjusted for our price
differentials. Please read Note 11 to the audited Mariner
financial statements contained in this prospectus. |
17
Operating
Data
The following table presents certain information with respect to
our production and operating data for the periods presented.
Information for the six months ended June 30, 2006 and the
year ended December 31, 2005 also is presented on a pro
forma basis, giving effect to our merger with Forest Energy
Resources as though it had been consummated on January 1,
2005. The merger was consummated on March 2, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Year Ended
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
December 31,
|
|
|
Ended
|
|
|
Year Ended December 31,
|
|
|
|
June 30, 2006
|
|
|
2005
|
|
|
June 30, 2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
28.9
|
|
|
|
67.5
|
|
|
|
22.7
|
|
|
|
18.4
|
|
|
|
23.8
|
|
|
|
23.8
|
|
Oil (Mbbls)
|
|
|
1.8
|
|
|
|
4.6
|
|
|
|
1.5
|
|
|
|
1.8
|
|
|
|
2.3
|
|
|
|
1.6
|
|
Total natural gas equivalent (Bcfe)
|
|
|
39.7
|
|
|
|
94.9
|
|
|
|
31.8
|
|
|
|
29.1
|
|
|
|
37.6
|
|
|
|
33.4
|
|
Average daily natural gas
equivalent (MMcfe)
|
|
|
219.3
|
|
|
|
260.0
|
|
|
|
175.8
|
|
|
|
79.7
|
|
|
|
103.0
|
|
|
|
91.5
|
|
Average realized sales price
per unit (excluding the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
7.44
|
|
|
$
|
8.04
|
|
|
$
|
7.14
|
|
|
$
|
8.33
|
|
|
$
|
6.12
|
|
|
$
|
5.43
|
|
Oil ($/bbl)
|
|
|
59.97
|
|
|
|
48.86
|
|
|
|
61.20
|
|
|
|
51.66
|
|
|
|
38.52
|
|
|
|
26.85
|
|
Total natural gas equivalent
($/Mcfe)
|
|
|
8.13
|
|
|
|
8.07
|
|
|
|
8.02
|
|
|
|
8.43
|
|
|
|
6.23
|
|
|
|
5.15
|
|
Average realized sales price
per unit (including the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
7.32
|
|
|
$
|
6.40
|
|
|
$
|
7.00
|
|
|
$
|
6.66
|
|
|
$
|
5.80
|
|
|
$
|
4.40
|
|
Oil ($/bbl)
|
|
|
56.85
|
|
|
|
34.18
|
|
|
|
57.53
|
|
|
|
41.23
|
|
|
|
33.17
|
|
|
|
23.74
|
|
Total natural gas equivalent
($/Mcfe)
|
|
|
7.91
|
|
|
|
6.20
|
|
|
|
7.74
|
|
|
|
6.74
|
|
|
|
5.70
|
|
|
|
4.27
|
|
Expenses ($/Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.37
|
|
|
$
|
1.17
|
|
|
$
|
1.18
|
|
|
$
|
1.03
|
|
|
$
|
0.68
|
|
|
$
|
0.74
|
|
Transportation
|
|
|
0.06
|
|
|
|
0.06
|
|
|
|
0.07
|
|
|
|
0.08
|
|
|
|
0.08
|
|
|
|
0.19
|
|
General and administrative, net(1)
|
|
|
|
|
|
|
|
|
|
|
0.55
|
|
|
|
1.27
|
|
|
|
0.23
|
|
|
|
0.24
|
|
Depreciation, depletion and
amortization (excluding impairments)(2)
|
|
|
3.44
|
|
|
|
3.47
|
|
|
|
3.45
|
|
|
|
2.04
|
|
|
|
1.73
|
|
|
|
1.45
|
|
|
|
|
(1) |
|
Net of overhead reimbursements received from other working
interest owners and amounts capitalized under the full cost
accounting method. Includes non-cash stock compensation expense
of $7.9 million for the six months ended June 30, 2006
and $25.7 million in 2005. General and administrative
expenses, net of capitalized amounts, are not included in pro
forma 2005 because accounts of such costs were not historically
maintained for the Forest Gulf of Mexico operations as a
separate business unit. We believe the overhead costs associated
with the Forest Gulf of Mexico operations in 2006 will
approximate $6.4 million, net of capitalized amounts. |
|
(2) |
|
Pro forma depreciation, depletion and amortization gives effect
to the acquisition of the Forest Gulf of Mexico operations and a
preliminary estimate of their
step-up in
value basis the unit of production method under the full cost
method of accounting. |
18
RISK
FACTORS
You should consider carefully the following risks, as well as
the other information set forth in this prospectus, before
deciding to participate in the exchange offer. Any of the
following risks could materially adversely affect our business,
financial condition or results of operations, which in turn
could adversely affect our ability to pay the notes. In such
case, you may lose all or part of your original investment.
Risks
Related to the Exchange Offer
If you
do not properly tender your old notes, you will continue to hold
unregistered outstanding notes and your ability to transfer
those notes will be adversely affected.
If you do not exchange your old notes for new notes in the
exchange offer, you will continue to be subject to the
restrictions on transfer of your old notes described in the
legend on the certificates representing your old notes. In
general, you may only offer or sell the old notes if they are
registered under the Securities Act and applicable state
securities laws or offered and sold under an exemption from
those requirements. We do not plan to register any sale of the
old notes under the Securities Act unless required to do so
under the limited circumstances set forth in the registration
rights agreement. In addition, the issuance of the new notes may
adversely affect the trading market for untendered, or tendered
but unaccepted, old notes. For further information regarding the
consequences of not tendering your old notes in the exchange
offer, see The Exchange Offer Consequences of
Failure to Exchange and Material United States
Federal Income Tax Considerations.
We will only issue new notes in exchange for old notes that you
timely and properly tender. Therefore, you should allow
sufficient time to ensure timely delivery of the old notes and
you should carefully follow the instructions on how to tender
your old notes. Neither we nor the exchange agent is required to
tell you of any defects or irregularities with respect to your
tender of old notes. See The Exchange Offer
Procedures for Tendering Old Notes and Description
of Senior Notes.
You
may find it difficult to sell your new notes.
Because there is no public market for the new notes, you may not
be able to resell them. The new notes will be registered under
the Securities Act but will constitute a new issue of securities
with no established trading market. An active market may not
develop for the new notes and any trading market that does
develop may not be liquid. We do not intend to apply to list the
new notes for trading on any securities exchange or to arrange
for quotation on any automated dealer quotation system. The
trading market for the new notes may be adversely affected by:
|
|
|
|
|
changes in the overall market for non-investment grade
securities;
|
|
|
|
changes in our financial performance or prospects;
|
|
|
|
the prospects for companies in our industry generally;
|
|
|
|
the number of holders of the new notes;
|
|
|
|
the interest of securities dealers in making a market for the
new notes; and
|
|
|
|
prevailing interest rates and general economic conditions.
|
Historically, the market for non-investment grade debt has been
subject to substantial volatility in prices. The market for the
new notes, if any, may be subject to similar volatility.
Prospective investors in the new notes should be aware that they
may be required to bear the financial risks of such investment
for an indefinite period of time.
Some
holders who exchange their old notes may be deemed to be
underwriters.
If you exchange your old notes in the exchange offer for the
purpose of participating in a distribution of the new notes, you
may be deemed to have received restricted securities and, if so,
will be required to comply
19
with the registration and prospectus delivery requirements of
the Securities Act in connection with any resale transaction.
See The Exchange Offer Resale of the New
Notes; Plan of Distribution.
Risks
Relating to the Oil and Natural Gas Industry and to Our
Business
Oil
and natural gas prices are volatile, and a decline in oil and
natural gas prices would reduce our revenues, profitability and
cash flow and impede our growth.
Our revenues, profitability and cash flow depend substantially
upon the prices and demand for oil and natural gas. The markets
for these commodities are volatile and even relatively modest
drops in prices can affect significantly our financial results
and impede our growth. Oil and natural gas prices are currently
at or near historical highs and may fluctuate and decline
significantly in the near future. Prices for oil and natural gas
fluctuate in response to relatively minor changes in the supply
and demand for oil and natural gas, market uncertainty and a
variety of additional factors beyond our control, such as:
|
|
|
|
|
domestic and foreign supply of oil and natural gas;
|
|
|
|
price and quantity of foreign imports;
|
|
|
|
actions of the Organization of Petroleum Exporting Countries and
other state-controlled oil companies relating to oil price and
production controls;
|
|
|
|
level of consumer product demand;
|
|
|
|
domestic and foreign governmental regulations;
|
|
|
|
political conditions in or affecting other oil-producing and
natural gas-producing countries, including the current conflicts
in the Middle East and conditions in South America and Russia;
|
|
|
|
weather conditions;
|
|
|
|
technological advances affecting oil and natural gas consumption;
|
|
|
|
overall U.S. and global economic conditions; and
|
|
|
|
price and availability of alternative fuels.
|
Further, oil prices and natural gas prices do not necessarily
fluctuate in direct relationship to each other. Because
approximately 62% of our estimated proved reserves (68% on a pro
forma basis) as of December 31, 2005 were natural gas
reserves, our financial results are more sensitive to movements
in natural gas prices. Lower oil and natural gas prices may not
only decrease our revenues on a per unit basis but also may
reduce the amount of oil and natural gas that we can produce
economically. This may result in our having to make substantial
downward adjustments to our estimated proved reserves and could
have a material adverse effect on our financial condition and
results of operations.
Reserve
estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates
or underlying assumptions will affect materially the quantities
and present value of our reserves, which may lower our bank
borrowing base and reduce our access to capital.
Estimating oil and natural gas reserves is complex and
inherently imprecise. It requires interpretation of the
available technical data and making many assumptions about
future conditions, including price and other economic
conditions. In preparing estimates we project production rates
and timing of development expenditures. We also analyze the
available geological, geophysical, production and engineering
data. The extent, quality and reliability of this data can vary.
This process also requires economic assumptions about matters
such as oil and natural gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves most
likely will vary from our estimates, perhaps significantly. In
addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development,
prevailing oil and natural gas prices and
20
other factors, many of which are beyond our control. At
December 31, 2005, 50% of our estimated proved reserves
were proved undeveloped (44% on a pro forma basis).
If the interpretations or assumptions we use in arriving at our
estimates prove to be inaccurate, the amount of oil and natural
gas that we ultimately recover may differ materially from the
estimated quantities and net present value of reserves shown in
this prospectus. See Business Estimated Proved
Reserves for information about our oil and gas reserves.
In
estimating future net revenues from proved reserves, we assume
that future prices and costs are fixed and apply a fixed
discount factor. If any such assumption or the discount factor
is materially inaccurate, our revenues, profitability and cash
flow could be materially less than our estimates.
The present value of future net revenues from our proved
reserves referred to in this prospectus is not necessarily the
actual current market value of our estimated oil and natural gas
reserves. In accordance with SEC requirements, we base the
estimated discounted future net cash flows from our proved
reserves on fixed prices and costs as of the date of the
estimate. Actual future prices and costs fluctuate over time and
may differ materially from those used in the present value
estimate. In addition, discounted future net cash flows are
estimated assuming that royalties to the Minerals Management
Service, or MMS, with respect to our affected offshore Gulf of
Mexico properties will be paid or suspended for the life of the
properties based upon oil and natural gas prices as of the date
of the estimate. See Business Royalty
Relief, and Business Legal
Proceedings. Since actual future prices fluctuate over
time, royalties may be required to be paid for various portions
of the life of the properties and suspended for other portions
of the life of the properties.
The timing of both the production and expenses from the
development and production of oil and natural gas properties
will affect both the timing of actual future net cash flows from
our proved reserves and their present value. In addition, the
10% discount factor that we use to calculate the net present
value of future net cash flows for reporting purposes in
accordance with the SECs rules may not necessarily be the
most appropriate discount factor. The effective interest rate at
various times and the risks associated with our business or the
oil and gas industry in general will affect the appropriateness
of the 10% discount factor in arriving at an accurate net
present value of future net cash flows.
If oil
and natural gas prices decrease, we may be required to
write-down the carrying value
and/or the
estimates of total reserves of our oil and natural gas
properties.
Accounting rules applicable to us require that we review
periodically the carrying value of our oil and natural gas
properties for possible impairment. Based on specific market
factors and circumstances at the time of prospective impairment
reviews and the continuing evaluation of development plans,
production data, economics and other factors, we may be required
to write-down the carrying value of our oil and natural gas
properties. A write-down constitutes a non-cash charge to
earnings. We may incur non-cash charges in the future, which
could have a material adverse effect on our results of
operations in the period taken. We may also reduce our estimates
of the reserves that may be economically recovered, which could
have the effect of reducing the value of our reserves.
We
need to replace our reserves at a faster rate than companies
whose reserves have longer production periods. Our failure to
replace our reserves would result in decreasing reserves and
production over time.
Unless we conduct successful exploration and development
activities or acquire properties containing proven reserves, our
proved reserves will decline as reserves are depleted. Producing
oil and natural gas reserves are generally characterized by
declining production rates that vary depending on reservoir
characteristics and other factors. High production rates
generally result in recovery of a relatively higher percentage
of reserves from properties during the initial few years of
production. A significant portion of our current operations are
conducted in the Gulf of Mexico, especially since our merger
with Forest Energy Resources. Production from reserves in the
Gulf of Mexico generally declines more rapidly than reserves
from reservoirs in other producing regions. As a result, our
need to replace reserves from new investments is relatively
greater than those of producers who produce their reserves over
a longer time period, such as those
21
producers whose reserves are located in areas where the rate of
reserve production is lower. If we are not able to find, develop
or acquire additional reserves to replace our current and future
production, our production rates will decline even if we drill
the undeveloped locations that were included in our proved
reserves. Our future oil and natural gas reserves and
production, and therefore our cash flow and income, are
dependent on our success in economically finding or acquiring
new reserves and efficiently developing our existing reserves.
Approximately
65% of our total estimated proved reserves are either developed
non-producing or undeveloped (71% on a pro forma basis), and
those reserves may not ultimately be produced or
developed.
As of December 31, 2005, approximately 15% of our total
estimated proved reserves were developed non-producing (27% on a
pro forma basis) and approximately 50% were undeveloped (44% on
a pro forma basis). These reserves may not ultimately be
developed or produced. Furthermore, not all of our undeveloped
or developed non-producing reserves may be ultimately produced
during the time periods we have planned, at the costs we have
budgeted, or at all, which in turn may have in a material
adverse effect on our results of operations.
Any
production problems related to our Gulf of Mexico properties
could reduce our revenue, profitability and cash flow
materially.
A substantial portion of our exploration and production
activities is located in the Gulf of Mexico. This concentration
of activity makes us more vulnerable than some other industry
participants to the risks associated with the Gulf of Mexico,
including delays and increased costs relating to adverse weather
conditions such as hurricanes, which are common in the Gulf of
Mexico during certain times of the year, drilling rig and other
oilfield services and compliance with environmental and other
laws and regulations.
Our
exploration and development activities may not be commercially
successful.
Exploration activities involve numerous risks, including the
risk that no commercially productive oil or natural gas
reservoirs will be discovered. In addition, the future cost and
timing of drilling, completing and producing wells is often
uncertain. Furthermore, drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors,
including:
|
|
|
|
|
unexpected drilling conditions;
|
|
|
|
pressure or irregularities in formations;
|
|
|
|
equipment failures or accidents;
|
|
|
|
adverse weather conditions, including hurricanes, which are
common in the Gulf of Mexico during certain times of the year;
|
|
|
|
compliance with governmental regulations;
|
|
|
|
unavailability or high cost of drilling rigs, equipment or labor;
|
|
|
|
reductions in oil and natural gas prices; and
|
|
|
|
limitations in the market for oil and natural gas.
|
If any of these factors were to occur with respect to a
particular project, we could lose all or a part of our
investment in the project, or we could fail to realize the
expected benefits from the project, either of which could
materially and adversely affect our revenues and profitability.
Our
exploratory drilling projects are based in part on seismic data,
which is costly and cannot ensure the commercial success of the
project.
Our decisions to purchase, explore, develop and exploit
prospects or properties depend in part on data obtained through
geophysical and geological analyses, production data and
engineering studies, the results of which are often uncertain.
Even when used and properly interpreted,
3-D seismic
data and visualization
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techniques only assist geoscientists and geologists in
identifying subsurface structures and hydrocarbon indicators.
3-D seismic
data does not enable an interpreter to conclusively determine
whether hydrocarbons are present or producible economically. In
addition, the use of
3-D seismic
and other advanced technologies require greater predrilling
expenditures than other drilling strategies. Because of these
factors, we could incur losses as a result of exploratory
drilling expenditures. Poor results from exploration activities
could have a material adverse effect on our future cash flows,
ability to replace reserves and results of operations.
Oil
and gas drilling and production involve many business and
operating risks, any one of which could reduce our levels of
production, cause substantial losses or prevent us from
realizing profits.
Our business is subject to all of the operating risks associated
with drilling for and producing oil and natural gas, including:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of underground natural gas, oil and
formation water;
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natural disasters, such as hurricanes and other adverse weather
conditions;
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pipe or cement failures;
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casing collapses;
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lost or damaged oilfield drilling and service tools;
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abnormally pressured formations; and
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environmental hazards, such as natural gas leaks, oil spills,
pipeline ruptures and discharges of toxic gases.
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If any of these events occurs, we could incur substantial losses
as a result of injury or loss of life, severe damage to and
destruction of property, natural resources and equipment,
pollution and other environmental damage,
clean-up
responsibilities, regulatory investigation and penalties,
suspension of our operations and repairs to resume operations.
Our
offshore operations involve special risks that could increase
our cost of operations and adversely affect our ability to
produce oil and gas.
Offshore operations are subject to a variety of operating risks
specific to the marine environment, such as capsizing,
collisions and damage or loss from hurricanes or other adverse
weather conditions. These conditions can cause substantial
damage to facilities and interrupt production. As a result, we
could incur substantial liabilities that could reduce or
eliminate the funds available for exploration, development or
leasehold acquisitions, or result in loss of equipment and
properties. For more information on the impact of recent
hurricanes on our operations, see Managements
Discussion and Analysis of Financial Condition and Results of
Operations Recent Developments.
Exploration for oil or natural gas in the deepwater of the Gulf
of Mexico generally involves greater operational and financial
risks than exploration on the shelf. Deepwater drilling
generally requires more time and more advanced drilling
technologies, involving a higher risk of technological failure
and usually higher drilling costs. Our deepwater wells utilize
subsea completion and tieback technology. As of
September 30, 2006, we had 18 subsea wells. These
wells were tied back to 13 host production facilities for
production processing. An additional nine wells were then under
development for tieback to five additional host production
facilities. The installation of subsea production systems to
tieback and operate subsea wells requires substantial time and
the use of advanced and very sophisticated installation
equipment supported by remotely operated vehicles. These
operations may encounter mechanical difficulties and equipment
failures that could result in significant cost overruns.
Furthermore, the deepwater operations generally lack the
physical
23
and oilfield service infrastructure present in the shallow
waters of the Gulf of Mexico. As a result, a significant amount
of time may elapse between a deepwater discovery and our
marketing of the associated oil or natural gas, increasing both
the financial and operational risk involved with these
operations. Because of the lack and high cost of infrastructure,
some reserve discoveries in the deepwater may never be produced
economically.
Our
hedging transactions may not protect us adequately from
fluctuations in oil and natural gas prices and may limit future
potential gains from increases in commodity prices or result in
losses.
We enter into hedging arrangements from time to time to reduce
our exposure to fluctuations in oil and natural gas prices and
to achieve more predictable cash flow. These financial
arrangements typically take the form of price swap contracts and
costless collars. Hedging arrangements expose us to the risk of
financial loss in some circumstances, including situations when
the other party to the hedging contract defaults on its contract
or production is less than expected. During periods of high
commodity prices, hedging arrangements may limit significantly
the extent to which we can realize financial gains from such
higher prices. For example, our hedging arrangements reduced the
benefit we received from increases in the prices for oil and
natural gas by approximately $49 million and
$12 million for the calendar year 2005 and six months ended
June 30, 2006, respectively. Although we currently maintain
an active hedging program, we may choose not to engage in
hedging transactions in the future. As a result, we may be
affected adversely during periods of declining oil and natural
gas prices.
We
will require additional capital to fund our future activities.
If we fail to obtain additional capital, we may not be able to
implement fully our business plan, which could lead to a decline
in reserves.
We depend on our ability to obtain financing beyond our cash
flow from operations. Historically, we have financed our
business plan and operations primarily with internally generated
cash flow, bank borrowings, proceeds from the sale of oil and
natural gas properties, exploration arrangements with other
parties, the issuance of debt securities, privately raised
equity and, prior to the bankruptcy of Enron Corp. (our indirect
parent company until March 2, 2004), borrowings from Enron
affiliates. In the future, we will require substantial capital
to fund our business plan and operations. We expect to be
required to meet our needs from our excess cash flow, debt
financings and additional equity offerings (subject to certain
federal tax limitations during the two-year period following the
spin-off). Sufficient capital may not be available on acceptable
terms or at all. If we cannot obtain additional capital
resources, we may curtail our drilling, development and other
activities or be forced to sell some of our assets on
unfavorable terms.
The issuance of additional debt would require that a portion of
our cash flow from operations be used for the payment of
interest on our debt, thereby reducing our ability to use our
cash flow to fund working capital, capital expenditures,
acquisitions and general corporate requirements, which could
place us at a competitive disadvantage relative to other
competitors. Additionally, if revenues decrease as a result of
lower oil or natural gas prices, operating difficulties or
declines in reserves, our ability to obtain the capital
necessary to undertake or complete future exploration and
development programs and to pursue other opportunities may be
limited, which could result in a curtailment of our operations
relating to exploration and development of our prospects, which
in turn could result in a decline in our oil and natural gas
reserves.
Properties
we acquire (including the Forest Gulf of Mexico properties we
acquired in March 2006) may not produce as projected, and
we may be unable to determine reserve potential, identify
liabilities associated with the properties or obtain protection
from sellers against such liabilities.
Properties we acquire, including the Forest Gulf of Mexico
properties, may not produce as expected, may be in an unexpected
condition and may subject us to increased costs and liabilities,
including environmental liabilities. The reviews we conduct of
acquired properties prior to acquisition are not capable of
identifying all potential adverse conditions. Generally, it is
not feasible to review in depth every individual property
involved in each acquisition. Ordinarily, we will focus our
review efforts on the higher value properties or properties with
known adverse conditions and will sample the remainder. However,
even a detailed review of records and properties may not
necessarily reveal existing or potential problems or permit a
buyer to become sufficiently
24
familiar with the properties to assess fully their condition,
any deficiencies, and development potential. Inspections may not
always be performed on every well, and environmental problems,
such as ground water contamination, are not necessarily
observable even when an inspection is undertaken.
Market
conditions or transportation impediments may hinder our access
to oil and natural gas markets or delay our
production.
Market conditions, the unavailability of satisfactory oil and
natural gas transportation or the remote location of our
drilling operations may hinder our access to oil and natural gas
markets or delay our production. The availability of a ready
market for our oil and natural gas production depends on a
number of factors, including the demand for and supply of oil
and natural gas and the proximity of reserves to pipelines or
trucking and terminal facilities. In deepwater operations, the
availability of a ready market depends on the proximity of and
our ability to tie into existing production platforms owned or
operated by others and the ability to negotiate commercially
satisfactory arrangements with the owners or operators. We may
be required to shut in wells or delay initial production for
lack of a market or because of inadequacy or unavailability of
pipeline or gathering system capacity. When that occurs, we are
unable to realize revenue from those wells until the production
can be tied to a gathering system. This can result in
considerable delays from the initial discovery of a reservoir to
the actual production of the oil and natural gas and realization
of revenues.
The
unavailability or high cost of drilling rigs, equipment,
supplies or personnel could affect adversely our ability to
execute on a timely basis our exploration and development plans
within budget, which could have a material adverse effect on our
financial condition and results of operations.
Shortages in availability or the high cost of drilling rigs,
equipment, supplies or personnel could delay or affect adversely
our exploration and development operations, which could have a
material adverse effect on our financial condition and results
of operations. An increase in drilling activity in the
U.S. or the Gulf of Mexico could increase the cost and
decrease the availability of necessary drilling rigs, equipment,
supplies and personnel.
Competition
in the oil and natural gas industry is intense, and many of our
competitors have resources that are greater than ours giving
them an advantage in evaluating and obtaining properties and
prospects.
We operate in a highly competitive environment for acquiring
prospects and productive properties, marketing oil and natural
gas and securing equipment and trained personnel. Many of our
competitors are major and large independent oil and natural gas
companies, and possess and employ financial, technical and
personnel resources substantially greater than ours. Those
companies may be able to develop and acquire more prospects and
productive properties than our financial or personnel resources
permit. Our ability to acquire additional prospects and discover
reserves in the future will depend on our ability to evaluate
and select suitable properties and consummate transactions in a
highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
natural gas industry. Larger competitors may be better able to
withstand sustained periods of unsuccessful drilling and absorb
the burden of changes in laws and regulations more easily than
we can, which would adversely affect our competitive position.
We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing
hydrocarbons, attracting and retaining quality personnel and
raising additional capital.
Financial
difficulties encountered by our farm-out partners or third-party
operators could adversely affect our ability to timely complete
the exploration and development of our prospects.
From time to time, we enter into farm-out agreements to fund a
portion of the exploration and development costs of our
prospects. Moreover, other companies operate some of the other
properties in which we have an ownership interest. Liquidity and
cash flow problems encountered by our partners and co-owners of
our properties may lead to a delay in the pace of drilling or
project development that may be detrimental to a project. In
addition, our farm-out partners and working interest owners may
be unwilling or unable to pay their share of the costs of
projects as they become due. In the case of a farm-out partner,
we may have to
25
obtain alternative funding in order to complete the exploration
and development of the prospects subject to the farm-out
agreement. In the case of a working interest owner, we may be
required to pay the working interest owners share of the
project costs. We cannot assure you that we would be able to
obtain the capital necessary in order to fund either of these
contingencies.
We
cannot control the timing or scope of drilling and development
activities on properties we do not operate, and therefore we may
not be in a position to control the associated costs or the rate
of production of the reserves.
Other companies operate some of the properties in which we have
an interest. As a result, we have a limited ability to exercise
influence over operations for these properties or their
associated costs. Our dependence on the operator and other
working interest owners for these projects and our limited
ability to influence operations and associated costs could
materially adversely affect the realization of our targeted
returns on capital in drilling or acquisition activities. The
success and timing of drilling and development activities on
properties operated by others therefore depend upon a number of
factors that are outside of our control, including timing and
amount of capital expenditures, the operators expertise
and financial resources, approval of other participants in
drilling wells and selection of technology.
Compliance
with environmental and other government regulations could be
costly and could affect production negatively.
Exploration for and development, production and sale of oil and
natural gas in the U.S. and the Gulf of Mexico are subject to
extensive federal, state and local laws and regulations,
including environmental and health and safety laws and
regulations. We may be required to make large expenditures to
comply with these environmental and other requirements. Matters
subject to regulation include, among others, environmental
assessment prior to development, discharge and emission permits
for drilling and production operations, drilling bonds, and
reports concerning operations and taxation.
Under these laws and regulations, and also common law causes of
action, we could be liable for personal injuries, property
damage, oil spills, discharge of pollutants and hazardous
materials, remediation and
clean-up
costs and other environmental damages. Failure to comply with
these laws and regulations or to obtain or comply with required
permits may result in the suspension or termination of our
operations and subject us to remedial obligations as well as
administrative, civil and criminal penalties. Moreover, these
laws and regulations could change in ways that substantially
increase our costs. We cannot predict how agencies or courts
will interpret existing laws and regulations, whether additional
or more stringent laws and regulations will be adopted or the
effect these interpretations and adoptions may have on our
business or financial condition. For example, the Oil Pollution
Act of 1990, or OPA, imposes a variety of regulations on
responsible parties related to the prevention of oil
spills. The implementation of new, or the modification of
existing, environmental laws or regulations promulgated pursuant
to the OPA could have a material adverse impact on us. Further,
Congress or the MMS could decide to limit exploratory drilling
or natural gas production in additional areas of the Gulf of
Mexico. Accordingly, any of these liabilities, penalties,
suspensions, terminations or regulatory changes could have a
material adverse effect on our financial condition and results
of operations. See Business Regulation
for more information on our regulatory and environmental matters.
Compliance
with MMS regulations could significantly delay or curtail our
operations or require us to make material expenditures, all of
which could have a material adverse effect on our financial
condition or results of operations.
A significant portion of our operations are located on federal
oil and natural gas leases that are administered by the MMS. As
an offshore operator, we must obtain MMS approval for our
exploration, development and production plans prior to
commencing such operations. The MMS has promulgated regulations
that, among other things, require us to meet stringent
engineering and construction specifications, restrict the
flaring or venting of natural gas, govern the plug and
abandonment of wells located offshore and
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the installation and removal of all production facilities, and
govern the calculation of royalties and the valuation of crude
oil produced from federal leases.
Our
insurance may not protect us against our business and operating
risks.
We maintain insurance for some, but not all, of the potential
risks and liabilities associated with our business. For some
risks, we may not obtain insurance if we believe the cost of
available insurance is excessive relative to the risks
presented. As a result of market conditions, premiums and
deductibles for certain insurance policies can increase
substantially, and in some instances, certain insurance may
become unavailable or available only for reduced amounts of
coverage. As a result, we may not be able to renew our existing
insurance policies or procure other desirable insurance on
commercially reasonable terms, if at all.
Although we maintain insurance at levels which we believe are
appropriate and consistent with industry practice, we are not
fully insured against all risks, including drilling and
completion risks that are generally not recoverable from third
parties or insurance. In addition, pollution and environmental
risks generally are not fully insurable. Losses and liabilities
from uninsured and underinsured events and delay in the payment
of insurance proceeds could have a material adverse effect on
our financial condition and results of operations. The impact of
Hurricanes Katrina and Rita have resulted in escalating
insurance costs and less favorable coverage terms. In addition,
we have not yet been able to determine the full extent of our
insurance recovery and the net cost to us resulting from the
hurricanes. See Business Insurance
Matters for more information.
Risks
Relating to Our Merger with Forest Energy Resources
The
integration of the Forest Gulf of Mexico operations will be
difficult, and will divert our managements attention away
from our normal operations.
There is a significant degree of difficulty and management
involvement inherent in the process of integrating the Forest
Gulf of Mexico operations. These difficulties include:
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the challenge of integrating the Forest Gulf of Mexico
operations while carrying on the ongoing operations of our
business;
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the challenge of managing a significantly larger company, with
more than twice the PV10 of Mariner prior to the merger;
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the possibility of faulty assumptions underlying our
expectations;
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the difficulty associated with coordinating geographically
separate organizations;
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the challenge of integrating the business cultures of the two
companies;
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attracting and retaining personnel associated with the Forest
Gulf of Mexico operations following the merger; and
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the challenge and cost of integrating the information technology
systems of the two companies.
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The process of integrating our operations could cause an
interruption of, or loss of momentum in, the activities of our
business. Members of our senior management may be required to
devote considerable amounts of time to this integration process,
which will decrease the time they will have to manage our
business. If our senior management is not able to effectively
manage the integration process, or if any significant business
activities are interrupted as a result of the integration
process, our business could suffer.
If we
fail to realize the anticipated benefits of the merger, our
results of operations may be lower than we expect.
The success of the merger will depend, in part, on our ability
to realize the anticipated growth opportunities from combining
the Forest Gulf of Mexico operations with Mariner. Even if we
are able to successfully combine the two businesses, it may not
be possible to realize the full benefits of the proved
27
reserves, enhanced growth of production volume, cost savings
from operating synergies and other benefits that we currently
expect to result from the merger, or realize these benefits
within the time frame that is currently expected. The benefits
of the merger may be offset by operating losses relating to
changes in commodity prices, or in oil and gas industry
conditions, or by risks and uncertainties relating to the
combined companys exploratory prospects, or an increase in
operating or other costs or other difficulties. If we fail to
realize the benefits we anticipate from the merger, our results
of operations may be adversely affected.
We
expect to incur significant charges relating to the integration
plan that could materially and adversely affect our
period-to-period
results of operations.
We anticipate that from time to time we will incur charges to
our earnings in connection with the integration of the Forest
Gulf of Mexico operations into our business. These charges will
include expenses incurred in connection with relocating and
retaining employees and increased professional and consulting
costs. We also expect to incur significant expenses related to
being a public company. We are not yet able to quantify the
costs or timing of the integration. Some factors affecting the
cost of the integration include the training of new employees,
the amount of severance and other employee-related payments
resulting from the merger, and the limited length of time during
which transitional services are provided by Forest. During the
six months ended June 30, 2006, we incurred approximately
$2.5 million of such costs.
In
order to preserve the tax-free treatment of the spin-off of
Forest Energy Resources, we are required to abide by potentially
significant restrictions which could limit our ability to
undertake certain corporate actions (such as the issuance of our
common shares or the undertaking of a change in control) that
otherwise could be advantageous.
In connection with the merger we entered into a tax sharing
agreement, which imposes ongoing restrictions on Forest and on
us to ensure that applicable statutory requirements under the
Internal Revenue Code of 1986, as amended, or the Code, and
applicable Treasury regulations continue to be met so that the
spin-off of Forest Energy Resources remains tax-free to Forest
and its shareholders. As a result of these restrictions, our
ability to engage in certain transactions, such as the
redemption of our common stock, the issuance of equity
securities and the utilization of our stock as currency in an
acquisition, will be limited for a period of two years following
the spin-off.
If Forest or Mariner takes or permits an action to be taken (or
omits to take an action) that causes the spin-off to become
taxable, the relevant entity generally will be required to bear
the cost of the resulting tax liability to the extent that the
liability results from the actions or omissions of that entity.
If the spin-off became taxable, Forest would be expected to
recognize a substantial amount of income, which would result in
a material amount of taxes. Any such taxes allocated to us would
be expected to be material to us, and could cause our business,
financial condition and operating results to suffer. These
restrictions may reduce our ability to engage in certain
business transactions that otherwise might be advantageous to us
and could have a negative impact on our business.
Risks
Relating to the Notes
We may
not be able to generate enough cash flow to meet our debt
obligations.
We expect our earnings and cash flow to vary significantly from
year to year due to the cyclical nature of our industry. As a
result, the amount of debt that we can manage in some periods
may not be appropriate for us in other periods. Additionally,
our future cash flow may be insufficient to meet our debt
obligations and commitments, including the notes. Any
insufficiency could negatively impact our business. A range of
economic, competitive, business and industry factors will affect
our future financial performance, and, as a result, our ability
to generate cash flow from operations and to pay our debt,
including the notes. Many of these factors, such as oil and gas
prices, economic and financial conditions in our industry and
the global economy or competitive initiatives of our
competitors, are beyond our control.
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If we do not generate enough cash flow from operations to
satisfy our debt obligations, we may have to undertake
alternative financing plans, such as:
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refinancing or restructuring our debt;
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selling assets;
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reducing or delaying capital investments; or
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seeking to raise additional capital.
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However, we cannot assure you that undertaking alternative
financing plans, if necessary, would allow us to meet our debt
obligations. Our inability to generate sufficient cash flow to
satisfy our debt obligations, including our obligations under
the notes, or to obtain alternative financing, could materially
and adversely affect our business, financial condition, results
of operations and prospects.
The
notes and the guarantees will be unsecured and effectively
subordinated to our and our subsidiary guarantors existing
and future secured indebtedness.
The notes and the guarantees are general unsecured senior
obligations ranking effectively junior in right of payment to
all existing and future secured debt of ours and that of each
subsidiary guarantor, respectively, including obligations under
our credit facility, to the extent of the value of the
collateral securing the debt. As of June 30, 2006, after
giving effect to borrowings under our amended and restated
credit facility and to the offering of the old notes and the
application of the proceeds therefrom, our total indebtedness
was $457.0 million, $300.0 million of which was the
old notes and $157.0 million of which effectively was
senior in right of payment to the notes to the extent of the
value of the collateral securing that indebtedness. We also then
had two letters of credit outstanding for $40.0 million and
$4.2 million, each of which effectively is senior to the
notes to the extent of the collateral securing such
indebtedness. Further, we then had $201.3 million in
additional borrowing capacity under our credit facility which if
borrowed would have been secured debt effectively senior in
right of payment to the notes to the extent of the value of the
collateral securing that indebtedness.
If we or a subsidiary guarantor are declared bankrupt, become
insolvent or are liquidated or reorganized, any secured debt of
ours or that subsidiary guarantor will be entitled to be paid in
full from our assets or the assets of the guarantor, as
applicable, securing that debt before any payment may be made
with respect to the notes or the affected guarantees. Holders of
the notes participate ratably with all holders of our unsecured
indebtedness that does not rank junior to the notes, including
all of our other general creditors, based upon the respective
amounts owed to each holder or creditor, in our remaining
assets. In any of the foregoing events, we cannot assure you
that there will be sufficient assets to pay amounts due on the
notes. As a result, holders of the notes would likely receive
less, ratably, than holders of secured indebtedness.
Our
debt level and the covenants in the agreements governing our
debt could negatively impact our financial condition, results of
operations and business prospects and prevent us from fulfilling
our obligations under the notes.
Our level of indebtedness, and the covenants contained in the
agreements governing our debt, could have important consequences
for our operations, including by:
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making it more difficult for us to satisfy our obligations under
the notes or other debt and increasing the risk that we may
default on our debt obligations;
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requiring us to dedicate a substantial portion of our cash flow
from operations to required payments on debt, thereby reducing
the availability of cash flow for working capital, capital
expenditures and other general business activities;
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limiting our ability to obtain additional financing in the
future for working capital, capital expenditures, acquisitions
and general corporate and other activities;
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limiting managements discretion in operating our business;
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limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate;
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detracting from our ability to withstand successfully a downturn
in our business or the economy generally;
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placing us at a competitive disadvantage against less leveraged
competitors; and
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making us vulnerable to increases in interest rates, because
debt under our credit facility will in some cases vary with
prevailing interest rates.
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We may be required to repay all or a portion of our debt on an
accelerated basis in certain circumstances. If we fail to comply
with the covenants and other restrictions in the agreements
governing our debt, it could lead to an event of default and the
consequent acceleration of our obligation to repay outstanding
debt. Our ability to comply with these covenants and other
restrictions may be affected by events beyond our control,
including prevailing economic and financial conditions.
In addition, under the terms of our credit facility and the
indenture, we must comply with certain financial covenants,
including current asset and total debt ratio requirements. Our
ability to comply with these covenants in future periods will
depend on our ongoing financial and operating performance, which
in turn will be subject to general economic conditions and
financial, market and competitive factors, in particular the
selling prices for our products and our ability to successfully
implement our overall business strategy.
The breach of any of the covenants in the indenture or the
credit facility could result in a default under the applicable
agreement which would permit the applicable lenders or
noteholders, as the case may be, to declare all amounts
outstanding thereunder to be due and payable, together with
accrued and unpaid interest. We may not have sufficient funds to
make such payments. If we are unable to repay our debt out of
cash on hand, we could attempt to refinance such debt, sell
assets or repay such debt with the proceeds from an equity
offering. We cannot assure you that we will be able to generate
sufficient cash flow to pay the interest on our debt or that
future borrowings, equity financings or proceeds from the sale
of assets will be available to pay or refinance such debt. The
terms of our debt, including our credit facility, may also
prohibit us from taking such actions. Factors that will affect
our ability to raise cash through an offering of our capital
stock, a refinancing of our debt or a sale of assets include
financial market conditions, restrictions in our tax sharing
agreement with Forest and the value of our assets and operating
performance at the time of such offering or other financing. We
cannot assure you that any such offering, refinancing or sale of
assets could be successfully completed.
Our
variable rate indebtedness subjects us to interest rate risk,
which could cause our debt service obligations to increase
significantly.
Borrowings under our credit facility bear interest at variable
rates and expose us to interest rate risk. If interest rates
increase, our debt service obligations on the variable rate
indebtedness would increase even though the amount borrowed
remained the same, and our net income and cash available for
servicing our indebtedness would decrease.
Despite
our and our subsidiaries current level of indebtedness, we
may still be able to incur substantially more debt. This could
further exacerbate the risks associated with our substantial
indebtedness.
We and our subsidiaries may be able to incur substantial
additional indebtedness in the future, subject to certain
limitations. The terms of our indenture will not prohibit us or
our subsidiaries from doing so. For example, as of June 30,
2006, we were able to borrow up to $362.5 million on a
revolving basis under our credit facility. If new debt is added
to our current debt levels, the related risks that we and our
subsidiaries now face could intensify. Our level of indebtedness
could, for instance, prevent us from engaging in transactions
that might otherwise be beneficial to us or from making
desirable capital expenditures. This could put us at a
competitive disadvantage relative to other less leveraged
competitors that have more cash flow to devote to their
operations. In addition, the incurrence of additional
indebtedness could make it more difficult to satisfy our
existing financial obligations, including those relating to the
notes.
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We may
not be able to repurchase the notes upon a change of
control.
Upon the occurrence of certain change of control events, we are
required to offer to repurchase all or any part of the notes
then outstanding for cash at 101% of the principal amount. The
source of funds for any repurchase required as a result of any
change of control will be our available cash or cash generated
from our operations or other sources, including:
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borrowings under our credit facilities or other sources;
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sales of assets; or
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sales of equity.
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We cannot assure you that sufficient funds would be available at
the time of any change of control to repurchase your notes. In
addition, our credit facility prohibits, and any future credit
facilities may prohibit, such repurchases. Additionally, a
change of control (as defined in the indenture for
the notes) will be an event of default under our credit facility
that would permit the lenders to accelerate the debt outstanding
under the credit facility. Finally, using available cash to fund
the potential consequences of a change of control may impair our
ability to obtain additional financing in the future, which
could negatively impact our ability to conduct our business
operations.
A
subsidiary guarantee could be voided if it constitutes a
fraudulent transfer under U.S. bankruptcy or similar state
law, which would prevent the holders of the notes from relying
on that subsidiary to satisfy claims.
Under U.S. bankruptcy law and comparable provisions of
state fraudulent transfer laws, our subsidiary guarantees can be
voided, or claims under the subsidiary guarantees may be
subordinated to all other debts of that subsidiary guarantor if,
among other things, the subsidiary guarantor, at the time it
incurred the indebtedness evidenced by its guarantee or, in some
states, when payments become due under the guarantee, received
less than reasonably equivalent value or fair consideration for
the incurrence of the guarantee and:
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was insolvent or rendered insolvent by reason of such incurrence;
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was engaged in a business or transaction for which the
guarantors remaining assets constituted unreasonably small
capital; or
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intended to incur, or believed that it would incur, debts beyond
its ability to pay those debts as they mature.
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Our subsidiary guarantees may also be voided, without regard to
the above factors, if a court found that the subsidiary
guarantor entered into the guarantee with the actual intent to
hinder, delay or defraud its creditors.
A court would likely find that a subsidiary guarantor did not
receive reasonably equivalent value or fair consideration for
its guarantee if the subsidiary guarantor did not substantially
benefit directly or indirectly from the issuance of the
guarantees. If a court were to void a subsidiary guarantee, you
would no longer have a claim against the subsidiary guarantor.
Sufficient funds to repay the notes may not be available from
other sources, including the remaining subsidiary guarantors, if
any. In addition, the court might direct you to repay any
amounts that you already received from the subsidiary guarantor.
The measures of insolvency for purposes of fraudulent transfer
laws vary depending upon the governing law. Generally, a
guarantor would be considered insolvent if:
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the sum of its debts, including contingent liabilities, were
greater than the fair saleable value of all its assets;
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the present fair saleable value of its assets is less than the
amount that would be required to pay its probable liability on
its existing debts, including contingent liabilities, as they
become absolute and mature; or
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it could not pay its debts as they become due.
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Each subsidiary guarantee contains a provision intended to limit
the subsidiary guarantors liability to the maximum amount
that it could incur without causing the incurrence of
obligations under its subsidiary guarantee to be a fraudulent
transfer. Such provision may not be effective to protect the
subsidiary guarantees from being voided under fraudulent
transfer law.
A
financial failure by us or our subsidiaries may result in the
assets of any or all of those entities becoming subject to the
claims of all creditors of those entities.
A financial failure by us or our subsidiaries could affect
payment of the notes if a bankruptcy court were to substantively
consolidate us and our subsidiaries. If a bankruptcy court
substantively consolidated us and our subsidiaries, the assets
of each entity would become subject to the claims of creditors
of all entities. This would expose holders of notes not only to
the usual impairments arising from bankruptcy, but also to
potential dilution of the amount ultimately recoverable because
of the larger creditor base. Furthermore, forced restructuring
of the notes could occur through the cram-down
provisions of the bankruptcy code. Under these provisions, the
notes could be restructured over your objections as to their
general terms, primarily interest rate and maturity.
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THE
EXCHANGE OFFER
This section of the prospectus describes the proposed
exchange offer. While we believe that the description covers the
material terms of the exchange offer, this summary may not
contain all of the information that is important to you. You
should carefully read this entire document for a complete
understanding of the exchange offer.
Purpose
and Effects of the Exchange Offer
We initially issued $300.0 million principal amount of old
notes on April 24, 2006 in a private offering. The initial
purchasers subsequently offered and sold a portion of the old
notes only to qualified institutional buyers as
defined in and in compliance with Rule 144A and outside the
United States in compliance with Regulation S of the
Securities Act.
In connection with the sale of the old notes, we entered into an
exchange and registration rights agreement, which requires us.
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to cause the old notes to be registered under the Securities
Act, or
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to file with the SEC a registration statement under the
Securities Act with respect to an issue of new notes identical
in all material respects to the old notes, and
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use our commercially reasonable efforts to cause such
registration statement to become effective under the Securities
Act, and
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upon the effectiveness of that registration statement, to offer
to the holders of the old notes the opportunity to exchange
their old notes for a like principal amount of new notes, which
will be issued without a restrictive legend and which may be
reoffered and resold by the holder without restrictions or
limitations under the Securities Act.
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We are making the exchange offer to satisfy our obligations
under the exchange and registration rights agreement. The term
holder with respect to the exchange offer means any
person in whose name old notes are registered on our or the
Depository Trust Companys (DTC) books or any
other person who has obtained a properly completed bond power
from the registered holder, or any person whose old notes are
held of record by DTC who desires to deliver such old notes by
book-entry transfer at DTC.
We have not requested, and do not intend to request, an
interpretation by the staff of the SEC with respect to whether
the new notes issued in the exchange offer in exchange for the
old notes may be offered for sale, resold or otherwise
transferred by any holder without compliance with the
registration and prospectus delivery provisions of the
Securities Act. Based on interpretations by the staff of the SEC
set forth in no-action letters issued to third parties, we
believe the new notes issued in exchange for old notes may be
offered for resale, resold and otherwise transferred by any
holder without compliance with the registration and prospectus
delivery provisions of the Securities Act provided that:
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you are not a broker-dealer who purchased old notes directly
from us for resale pursuant to Rule 144A or any other
available exemption under the Securities Act,
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you are not our or any subsidiary guarantors
affiliate, or
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you acquire the new notes in the ordinary course of your
business and that you have no arrangement or understanding with
any person to participate in the distribution of the new notes.
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Any holder who tenders in the exchange offer with the intention
to participate, or for the purpose of participating, in a
distribution of the new notes or who is our affiliate may not
rely upon such interpretations by the staff of the SEC and, in
the absence of an exemption, must comply with the registration
and prospectus delivery requirements of the Securities Act in
connection with any secondary resale transaction. Any holder to
comply with such requirements may incur liabilities under the
Securities Act for which the holder is not indemnified by us.
Each broker-dealer (other than an affiliate of ours) that
receives new notes for its own account in the exchange offer
must acknowledge that it will deliver a prospectus meeting the
requirements of
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the Securities Act in connection with any resale of new notes.
The letter of transmittal states that by so acknowledging and by
delivering a prospectus, a broker-dealer will not be deemed to
admit that it is an underwriter within the meaning
of the Securities Act. We have agreed that, for a period of
90 days after the exchange date, we will make the
prospectus available to any broker-dealer for use in connection
with any such resale. See Plan of Distribution.
We are not making the exchange offer to, nor will we accept
surrenders for exchange from, holders of old notes in any
jurisdiction in which this exchange offer or its acceptance
would not comply with the securities or blue sky laws.
By tendering in the exchange offer, you will represent to us
that, among other things:
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you are acquiring the new notes in the exchange offer in the
ordinary course of your business, whether or not you are a
holder,
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you do not have an arrangement or understanding with any person
to participate in the distribution of the new notes within the
meaning of the Securities Act,
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you are not a broker-dealer, or you are a broker-dealer but will
receive new notes in exchange for old notes that were acquired
for your own account,
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neither you nor any other person is engaged in or intends to
participate in the distribution of the new notes, and
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you are not our affiliate within the meaning of
Rule 405 under the Securities Act or, if you are our
affiliate, you will comply with the registration and
prospectus delivery requirements of the Securities Act to the
extent applicable.
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Following the completion of the exchange offer, no notes will be
entitled to the liquidated damages payment applicable to the old
notes. Nor will holders of notes have any further registration
rights, and the old notes will continue to be subject to certain
restrictions on transfer. See Consequences of
Failure to Exchange. Accordingly, the liquidity of the
market for the old notes could be adversely affected. See
Risk Factors Risks Related to the Exchange
Offer There may be adverse consequences of a failure
to exchange.
Participation in the exchange offer is voluntary and you should
carefully consider whether to accept. We urge you to consult
your financial and tax advisors in making your own decisions on
whether to participate in the exchange offer.
Consequences
of Failure to Exchange
The old notes that are not exchanged for new notes in the
exchange offer will remain restricted securities and subject to
restrictions on transfer. Accordingly, such old notes may only
be resold
(1) to us, upon redemption thereof or otherwise,
(2) so long as the old notes are eligible for resale
pursuant to Rule 144A, to a person whom the seller
reasonably believes is a qualified institutional buyer within
the meaning of Rule 144A, purchasing for its own account or
for the account of a qualified institutional buyer to whom
notice is given that the resale, pledge or other transfer is
being made in reliance on Rule 144A,
(3) in an offshore transaction in accordance with
Regulation S under the Securities Act,
(4) pursuant to an exemption from registration in
accordance with Rule 144, if available, under the
Securities Act,
(5) in reliance on another exemption from the registration
requirements of the Securities Act, or
(6) pursuant to an effective registration statement under
the Securities Act.
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In all of the situations discussed above, the resale must be in
accordance with any applicable securities laws of any state of
the United States and subject to certain requirements of the
registrar or co-registrar being met, including receipt by the
registrar or co-registrar of a certification and, in the case of
(3), (4) and (5) above, an opinion of counsel
reasonably acceptable to us and the registrar.
To the extent old notes are tendered and accepted in the
exchange offer, the principal amount of outstanding old notes
will decrease with a resulting decrease in the liquidity in the
market therefor. Accordingly, the liquidity of the market of the
old notes could be adversely affected.
Terms of
the Exchange Offer
Upon the terms and subject to the conditions set forth in this
prospectus and in the letter of transmittal, we will accept any
and all old notes validly tendered and not withdrawn prior to
the Expiration Date. We will issue $1,000 principal amount of
new notes in exchange for each $1,000 principal amount of old
notes accepted in the exchange offer. Holders may tender some or
all of their old notes pursuant to the exchange offer. However,
old notes may be tendered only in integral multiples of $1,000
principal amount.
The form and terms of the new notes are the same as the form and
terms of the old notes, except that
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the new notes will have been registered under the Securities Act
and will not bear legends restricting their transfer pursuant to
the Securities Act,
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except as otherwise described above, holders of the new notes
will not be entitled to the rights of holders of old notes under
the registration rights agreement, and
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the new notes will not be entitled to liquidated damages.
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The new notes will evidence the same debt as the old notes that
they replace, and will be issued under, and be entitled to the
benefits of, the indenture which governs all of the notes.
Solely for reasons of administration and for no other purpose,
we have fixed the close of business on October 6, 2006, as
the record date for the exchange offer to determine the persons
to whom this prospectus and the letter of transmittal will be
mailed initially. Only a registered holder of old notes or such
holders legal representative or
attorney-in-fact
as reflected on the indenture trustees records may
participate in the exchange offer. There will be no fixed record
date for determining holders of the old notes entitled to
participate in the exchange offer.
Holders of the old notes do not have any appraisal or
dissenters rights under Delaware law or the indenture in
connection with the exchange offer. We intend to conduct the
exchange offer in accordance with the requirements of the
Exchange Act and the SECs rules and regulations thereunder.
We will be deemed to have accepted validly tendered old notes
when, as and if we have given oral or written notice thereof to
the exchange agent. The exchange agent will act as agent for the
tendering holders of the old notes for the purposes of receiving
the new notes. The new notes delivered in the exchange offer
will be issued on the earliest practicable date following our
acceptance for exchange of old notes.
If any tendered old notes are not accepted for exchange because
of an invalid tender, the occurrence of certain other events set
forth herein or otherwise, certificates for any such unaccepted
old notes will be returned, without expense, to the tendering
holder as promptly as practicable after the Expiration Date.
Holders who tender old notes in the exchange offer will not be
required to pay brokerage commissions or fees or, subject to the
instructions in the letter of transmittal, transfer taxes with
respect to the exchange of the old notes in the exchange offer.
We will pay all charges and expenses, other than certain taxes
and commissions or concessions of any brokers or dealers, in
connection with the exchange offer. See Fees
and Expenses.
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Expiration
Date; Extensions; Amendments
The term Expiration Date with respect to the
exchange offer means 5:00 p.m., New York City time, on
November 9, 2006 unless we, in our sole discretion, extend
the exchange offer, in which case the term Expiration
Date shall mean the latest date and time to which the
exchange offer is extended.
If we extend the exchange offer, we will notify the exchange
agent of any extension by oral or written notice and will make a
public announcement thereof, each prior to 9:00 a.m., New
York City time, on the next business day after the previously
scheduled Expiration Date.
We reserve the right, in our sole discretion,
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to extend the exchange offer,
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if any of the conditions set forth below under
Conditions to the Exchange Offer have
not been satisfied, to terminate the exchange offer, or
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to amend the terms of the exchange offer in any manner.
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We may effect any such delay, extension or termination by giving
oral or written notice thereof to the exchange agent.
Except as specified in the second paragraph under this heading,
we will make a public announcement of any such delay in
acceptance, extension, termination or amendment as promptly as
practicable. If we amend the exchange offer in a manner
determined by us to constitute a material change, we will
promptly disclose such amendment in a prospectus supplement that
will be distributed to the registered holders of the old notes.
The exchange offer will then be extended for a period of five to
ten business days, as required by law, depending upon the
significance of the amendment and the manner of disclosure to
the registered holders.
We will make a timely release of a public announcement of any
delay, extension, termination or amendment to the exchange offer
to the Dow Jones News Service.
Procedures
for Tendering Old Notes
Tenders of Old Notes. The tender by a holder
of old notes pursuant to any of the procedures set forth below
will constitute the tendering holders acceptance of the
terms and conditions of the exchange offer. Our acceptance for
exchange of old notes tendered pursuant to any of the procedures
described below will constitute a binding agreement between such
tendering holder and us in accordance with the terms and subject
to the conditions of the exchange offer. Only holders are
authorized to tender their old notes. The procedures by which
old notes may be tendered by beneficial owners that are not
holders will depend upon the manner in which the old notes are
held.
The Depository Trust Company, or DTC, has authorized DTC
participants that are beneficial owners of old notes through DTC
to tender their old notes as if they were holders. To effect a
tender, DTC participants should either (1) complete and
sign the letter of transmittal or a facsimile thereof, have the
signature thereon guaranteed if required by the letter of
transmittal, and mail or deliver the letter of transmittal or
such facsimile pursuant to the procedures for book-entry
transfer set forth below under Book-Entry
Delivery Procedures, or (2) transmit their acceptance
to DTC through the DTC Automated Tender Offer Program, or ATOP,
for which the transaction will be eligible, and follow the
procedures for book-entry transfer, set forth below under
Book-Entry Delivery Procedures.
Tender of Old Notes Held in Physical
Form. To tender old notes held in physical form
in the exchange offer
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a properly completed letter of transmittal applicable to such
notes (or a facsimile thereof) duly executed by the tendering
holder, and any other documents the letter of transmittal
requires, must be received by the exchange agent at one of its
addresses set forth in this prospectus, and tendered old notes
must be received by the exchange agent at such address (or
delivery effected through the deposit of old notes
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into the exchange agents account with DTC and making
book-entry delivery as set forth below), on or prior to the
Expiration Date, or
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the tendering holder must comply with the guaranteed delivery
procedures set forth below.
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Letters of transmittal or old notes should be sent only to the
exchange agent and should not be sent to us.
Tender of Old Notes Held Through a
Custodian. To tender old notes that a custodian
bank, depository, broker, trust company or other nominee holds
of record, the beneficial owner thereof must instruct such
holder to tender the old notes on the beneficial owners
behalf. A letter of instructions from the record owner to the
beneficial owner may be included in the materials provided along
with this prospectus which the beneficial owner may use in this
process to instruct the registered holder of such owners
old notes to effect the tender.
Tender of Old Notes Held Through DTC. To
tender old notes that are held through DTC, DTC participants
should either
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properly complete and duly execute the letter of transmittal (or
a facsimile thereof), and any other documents required by the
letter of transmittal, and mail or deliver the letter of
transmittal or such facsimile pursuant to the procedures for
book-entry transfer set forth below, or
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transmit their acceptance through ATOP, for which the
transaction will be eligible, and DTC will then edit and verify
the acceptance and send an Agents Message to the exchange
agent for its acceptance.
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The term Agents Message means a message
transmitted by DTC to, and received by, the exchange agent and
forming a part of the Book-Entry Confirmation, which states that
DTC has received an express acknowledgment from each participant
in DTC tendering the old notes and that such participant has
received the letter of transmittal and agrees to be bound by the
terms of the letter of transmittal and we may enforce such
agreement against such participant.
Tendering old notes held through DTC must be delivered to the
exchange agent pursuant to the book-entry delivery procedures
set forth below or the tendering DTC participant must comply
with the guaranteed delivery procedures set forth below.
The method of delivery of old notes and letters of transmittal,
any required signature guarantees and all other required
documents, including delivery through DTC and any acceptance or
Agents Message transmitted through ATOP, is at the
election and risk of the person tendering old notes and
delivering letters of transmittal. Except as otherwise provided
in the letter of transmittal, delivery will be deemed made only
when actually received or confirmed by the exchange agent. If
delivery is by mail, it is suggested that the holder use an
overnight or courier service, and that the mailing be made
sufficiently in advance of the Expiration Date to permit
delivery to the exchange agent prior to such date.
Except as provided below, unless the old notes being tendered
are deposited with the exchange agent on or prior to the
Expiration Date (accompanied by a properly completed and duly
executed letter of transmittal or a properly transmitted
Agents Message), we may, at our option, reject such
tender. Exchange of new notes for old notes will be made only
against deposit of the tendered old notes and delivery of all
other required documents.
Book-Entry Delivery Procedures. The exchange
agent will establish accounts with respect to the old notes at
DTC for purposes of the exchange offer within two business days
after the date of this prospectus, and any financial institution
that is a participant in DTC may make book-entry delivery of the
old notes by causing DTC to transfer such old notes into the
exchange agents account in accordance with DTCs
procedures for such transfer. However, although delivery of old
notes may be effected through book-entry at DTC, the letter of
transmittal (or facsimile thereof), with any required signature
guarantees or an Agents Message in connection with a
book-entry transfer, and any other required documents, must, in
any case, be transmitted to and received by the exchange agent
at one or more of its addresses set forth in this prospectus on
or prior to the Expiration Date, or compliance must be made with
the guaranteed delivery procedures described below. Delivery of
documents to DTC does not constitute delivery to the exchange
agent. The
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confirmation of a book-entry transfer into the exchange
agents account at DTC as described above is referred to as
a Book-Entry Confirmation.
Signatures on the Letter of Transmittal; Bond Powers and
Endorsements; Medallion Guarantee of
Signatures. If the letter of transmittal is
signed by the record holder of the old notes tendered thereby,
the signature must correspond exactly with the name as written
on the face of the old notes without alteration, enlargement or
any change whatsoever. If the letter of transmittal is signed by
a participant in DTC, the signature must correspond with the
name as it appears on the security position listing as the
holder of the old notes. If any tendered old notes are owned of
record by two or more joint owners, all of such owners must sign
the letter of transmittal.
If the letter of transmittal is signed by the registered holder
of old notes tendered thereby and the new notes issued in
exchange therefor are to be issued (or any untendered principal
amount of old notes is to be reissued) to the registered holder,
then such holder need not and should not endorse any tendered
old notes, nor provide a separate bond power. In any other case,
such holder must either properly endorse the old notes tendered
or transmit a properly completed separate bond power with the
letter of transmittal, with the signatures on the endorsement or
bond power guaranteed by a firm that is a member of a registered
national securities exchange or of the National Association of
Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondent in the United States or an
eligible guarantor institution within the meaning of
Rule 17Ad-15
under the Exchange Act, in each case that is a participant in
the Securities Transfer Agents Medallion Program, the New
York Stock Exchange Medallion Program or the Stock
Exchanges Medallion Program approved by the Securities
Transfer Association Inc. (an Eligible Institution).
If the letter of transmittal or any old notes or bond powers are
signed by one or more trustees, executors, administrators,
guardians, attorneys-in-fact, officers of corporations or others
acting in a fiduciary or representative capacity, such persons
should so indicate when signing, and, unless waived by us,
evidence satisfactory to us of their authority to act must be
submitted with the letter of transmittal.
No signature guarantee is required if
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this letter of transmittal (or facsimile hereof) is signed by
the registered holder of the old notes tendered thereby (or by a
participant in DTC whose name appears on a security position
listing as the owner of the tendered old notes) and the new
notes are to be issued directly to such registered holder (or,
if signed by a participant in DTC, deposited to such
participants account at DTC) and neither the box entitled
Special Issuance Instructions nor the box entitled
Special Delivery Instructions on the letter of
transmittal has been completed or
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such old notes are tendered for the account of an Eligible
Institution.
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In all other cases, all signatures on the letter of transmittal
must be guaranteed by an Eligible Institution.
Guaranteed Delivery. If you wish to tender
your old notes but they are not immediately available or if you
cannot deliver your old notes, the letter of transmittal or any
other required documents to the exchange agent or comply with
the applicable procedures under DTCs automated tender
offer program prior to the expiration date, you may tender if:
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the tender is made by or through an eligible institution;
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prior to 5:00 p.m., New York City time, on the expiration
date, the exchange agent receives from that eligible institution
either a properly completed and duly executed notice of
guaranteed delivery by facsimile transmission, mail, courier or
overnight delivery or a properly transmitted agents
message relating to a notice of guaranteed delivery:
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stating your name and address, the registration number or
numbers of your old notes and the principal amount of old notes
tendered;
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stating that the tender is being made thereby; and
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guaranteeing that, within three New York Stock Exchange trading
days after the expiration date of the exchange offer, the letter
of transmittal or facsimile thereof or agents message in
lieu thereof, together with the old notes or a book-entry
confirmation, and any other documents required by the letter of
transmittal, will be deposited by the eligible institution with
the exchange agent; and
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the exchange agent receives such properly completed and executed
letter of transmittal or facsimile or Agents Message, as
well as all tendered old notes in proper form for transfer or a
book-entry confirmation, and all other documents required by the
letter of transmittal, within three New York Stock Exchange
trading days after the expiration date.
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Upon request to the exchange agent, the exchange agent will send
a notice of guaranteed delivery to you if you wish to tender
your old notes according to the guaranteed delivery procedures
described above.
Determination of Validity. All questions as to
the validity, form, eligibility (including time of receipt),
acceptance and withdrawal of tendered old notes will be
determined by us in our sole discretion, which determination
will be final and binding. We reserve the absolute right to
reject any and all old notes not properly tendered or any old
notes our acceptance of which, in the opinion of our counsel,
would be unlawful.
We also reserve the right to waive any defects, irregularities
or conditions of tender as to particular old notes. The
interpretation of the terms and conditions of our exchange offer
(including the instructions in the letter of transmittal) by us
will be final and binding on all parties. Unless waived, any
defects or irregularities in connection with tenders of old
notes must be cured within such time as we shall determine.
Although we intend to notify holders of defects or
irregularities with respect to tenders of old notes through the
exchange agent, neither we, the exchange agent nor any other
person is under any duty to give such notice, nor shall they
incur any liability for failure to give such notification.
Tenders of old notes will not be deemed to have been made until
such defects or irregularities have been cured or waived.
Any old notes received by the exchange agent that are not
validly tendered and as to which the defects or irregularities
have not been cured or waived, or if old notes are submitted in
a principal amount greater than the principal amount of old
notes being tendered by such tendering holder, such unaccepted
or non-exchanged old notes will either be
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returned by the exchange agent to the tendering holders, or
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in the case of old notes tendered by book-entry transfer into
the exchange agents account at the book-entry transfer
facility pursuant to the book-entry transfer procedures
described above, credited to an account maintained with such
book-entry transfer facility.
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Withdrawal
of Tenders
Except as otherwise provided herein, tenders of old notes in the
exchange offer may be withdrawn, unless accepted for exchange as
provided in the exchange offer, at any time prior to the
Expiration Date.
To be effective, a written or facsimile transmission notice of
withdrawal must be received by the exchange agent at its address
set forth herein prior to the Expiration Date. Any such notice
of withdrawal must
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specify the name of the person having deposited the old notes to
be withdrawn,
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identify the old notes to be withdrawn, including the
certificate number or numbers of the particular certificates
evidencing the old notes (unless such old notes were tendered by
book-entry transfer), and aggregate principal amount of such old
notes, and
|
|
|
|
be signed by the holder in the same manner as the original
signature on the letter of transmittal (including any required
signature guarantees) or be accompanied by documents of transfer
sufficient to have the trustee under the indenture register the
transfer of the old notes into the name of the person
withdrawing such old notes.
|
If old notes have been delivered pursuant to the procedures for
book-entry transfer set forth in Procedures
for Tendering Old Notes Book-Entry Delivery
Procedures, any notice of withdrawal must
39
specify the name and number of the account at the appropriate
book-entry transfer facility to be credited with such withdrawn
old notes and must otherwise comply with such book-entry
transfer facilitys procedures.
If the old notes to be withdrawn have been delivered or
otherwise identified to the exchange agent, a signed notice of
withdrawal meeting the requirements discussed above is effective
immediately upon written or facsimile notice of withdrawal even
if physical release is not yet effected. A withdrawal of old
notes can only be accomplished in accordance with these
procedures.
All questions as to the validity, form and eligibility
(including time of receipt) of such notices will be determined
by us in our sole discretion, which determination shall be final
and binding on all parties. No withdrawal of old notes will be
deemed to have been properly made until all defects or
irregularities have been cured or expressly waived. Neither we,
the exchange agent nor any other person will be under any duty
to give notification of any defects or irregularities in any
notice of withdrawal or revocation, nor shall we or they incur
any liability for failure to give any such notification. Any old
notes so withdrawn will be deemed not to have been validly
tendered for purposes of the exchange offer and no new notes
will be issued with respect thereto unless the old notes so
withdrawn are retendered. Properly withdrawn old notes may be
retendered by following one of the procedures described above
under Procedures for Tendering Old Notes
at any time prior to the Expiration Date.
Any old notes which have been tendered but which are not
accepted for exchange due to the rejection of the tender due to
uncured defects or the prior termination of the exchange offer,
or which have been validly withdrawn, will be returned to the
holder thereof unless otherwise provided in the letter of
transmittal, as soon as practicable following the Expiration
Date or, if so requested in the notice of withdrawal, promptly
after receipt by us of notice of withdrawal without cost to such
holder.
Conditions
to the Exchange Offer
The exchange offer is not subject to any conditions, other than
that
|
|
|
|
|
the exchange offer, or the making of any exchange by a holder,
does not violate applicable law or any applicable interpretation
of the staff of the SEC,
|
|
|
|
no action or proceeding shall have been instituted or threatened
in any court or by or before any governmental agency with
respect to the exchange offer, which, in our judgment, might
impair our ability to proceed with the exchange offer,
|
|
|
|
there shall not have been adopted or enacted any law, statute,
rule or regulation which, in our judgment, would materially
impair our ability to proceed with the exchange offer, or
|
|
|
|
there shall not have occurred any material change in the
financial markets in the United States or any outbreak of
hostilities or escalation thereof or other calamity or crisis
the effect of which on the financial markets of the United
States, in our judgment, would materially impair our ability to
proceed with the exchange offer.
|
If we determine in our reasonable discretion that any of the
conditions to the exchange offer are not satisfied, we may
|
|
|
|
|
refuse to accept any old notes and return all tendered old notes
to the tendering holders,
|
|
|
|
extend the exchange offer and retain all old notes tendered
prior to the Expiration Date, subject, however, to the rights of
holders to withdraw such old notes, or
|
|
|
|
waive such unsatisfied conditions with respect to the exchange
offer and accept all validly tendered old notes which have not
been withdrawn.
|
If such waiver constitutes a material change to the exchange
offer, we will promptly disclose such waiver by means of a
prospectus supplement that will be distributed to the registered
holders, and will extend the exchange offer for a period of five
to ten business days, depending upon the significance of the
waiver and the
40
manner of disclosure to the registered holders, if the exchange
offer would otherwise expire during such five to ten business
day period.
Exchange
Agent
Wells Fargo Bank, N.A., the trustee under the indenture
governing the notes, has been appointed as exchange agent for
the exchange offer. You should direct questions and requests for
assistance, requests for additional copies of this prospectus or
of the letter of transmittal and requests for notices of
guaranteed delivery and other documents to the exchange agent
addressed as follows:
Delivery
by Registered or Certified Mail:
Wells Fargo Bank, N.A.
Corporate Trust Operations
MAC
N9303-121
P.O. Box 1517
Minneapolis, MN
55480-1517
Overnight
Delivery or Regular Mail:
Wells Fargo Bank, N.A.
Corporate Trust Operations
Sixth and Marquette
MAC
N9303-121
Minneapolis, MN 55479
To
Confirm by Telephone or for Information:
(800) 344-5128
Facsimile
Transmissions:
(612) 667-4927
Fees and
Expenses
We will bear the expenses of soliciting tenders. The principal
solicitation is being made by mail; however, additional
solicitation may be made by telegraph, telecopy, telephone or in
person by our or our affiliates officers and regular
employees.
No dealer-manager has been retained in connection with the
exchange offer and no payments will be made to brokers, dealers
or others soliciting acceptance of the exchange offer. However,
reasonable and customary fees will be paid to the exchange agent
for its services and it will be reimbursed for its reasonable
out-of-pocket
expenses.
Our out of pocket expenses for the exchange offer will include
fees and expenses of the exchange agent and the trustee under
the indenture, accounting and legal fees and printing costs,
among others.
We will pay all transfer taxes, if any, applicable to the
exchange of the old notes pursuant to the exchange offer. If,
however, a transfer tax is imposed for any reason other than the
exchange of the old notes pursuant to the exchange offer, then
the amount of any such transfer taxes (whether imposed on the
registered holder or any other persons) will be payable by the
tendering holder. If satisfactory evidence of payment of such
taxes or exemption therefrom is not submitted with the letter of
transmittal, the amount of such transfer taxes will be billed
directly to such tendering holder.
41
Accounting
Treatment for Exchange Offer
The new notes will be recorded at the carrying value of the old
notes and no gain or loss for accounting purposes will be
recognized. The expenses of the exchange offer will be amortized
over the term of the new notes.
Resale of
the New Notes; Plan of Distribution
Each broker-dealer that receives new notes for its own account
pursuant to the exchange offer must acknowledge that it will
deliver a prospectus in connection with any resale of new notes.
This prospectus, as it may be amended or supplemented from time
to time, may be used by a broker-dealer in connection with
resales of new notes received in exchange for old notes where
such old notes were acquired as a result of market-making
activities or other trading activities. In addition, until
January 8, 2007 (90 days after the date of this
prospectus), all dealers effecting transactions in the new
notes, whether or not participating in this distribution, may be
required to deliver a prospectus. This requirement is in
addition to the obligation of dealers to deliver a prospectus
when acting as underwriters and with respect to their unsold
allotments or subscriptions.
We will not receive any proceeds from any sale of new notes by
broker-dealers. New notes received by broker-dealers for their
own account pursuant to the exchange offer may be sold from time
to time in one or more transactions:
|
|
|
|
|
in the
over-the-counter
market,
|
|
|
|
in negotiated transactions,
|
|
|
|
through the writing of options on the new notes or a combination
of such methods of resale,
|
|
|
|
at market prices prevailing at the time of resale,
|
|
|
|
at prices related to such prevailing market prices, or
|
|
|
|
at negotiated prices.
|
Any such resale may be made directly to purchasers or to or
through brokers or dealers who may receive compensation in the
form of commissions or concessions from any such broker-dealer
or the purchasers of any such new notes.
Any broker-dealer that resells new notes received for its own
account pursuant to the exchange offer and any broker or dealer
that participates in a distribution of such new notes may be
deemed to be an underwriter within the meaning of
the Securities Act and any profit on any such resale of new
notes and any commission on concessions received by any such
persons may be deemed to be underwriting compensation under the
Securities Act. The letter of transmittal states that, by
acknowledging that it will deliver a prospectus and by
delivering a prospectus, a broker-dealer will not be deemed to
admit that it is an underwriter within the meaning
of the Securities Act.
42
USE OF
PROCEEDS
The exchange offer is intended to satisfy our obligations under
the registration rights agreement. We will not receive any
proceeds from the issuance of the new notes in the exchange
offer. In consideration for issuing the new notes as
contemplated in this prospectus, we will receive, in exchange,
outstanding old notes in like principal amount. We will cancel
all old notes surrendered in exchange for new notes in the
exchange offer. As a result, the issuance of the new notes will
not result in any increase or decrease in our indebtedness.
The net proceeds from the offering of the sale of the old notes
in the initial private placement were approximately
$287.9 million. We used those proceeds, together with cash
on hand, to repay borrowings under our amended and restated
credit facility. The borrowings under the credit facility were
used to:
|
|
|
|
|
refinance indebtedness incurred by Forest Energy Resources in
connection its acquisition by us.
|
|
|
|
pay transaction expenses associated with the merger; and
|
|
|
|
repay $165.0 million under our prior credit facility with
Union Bank of California.
|
43
CAPITALIZATION
The following table sets forth our consolidated capitalization
as of June 30, 2006.
This table should be read together with our financial statements
and the related notes included in this prospectus.
|
|
|
|
|
|
|
As of June 30,
|
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Long-term debt:
|
|
|
|
|
Credit facility
revolving note(1)
|
|
$
|
157,000
|
|
Senior Notes
|
|
|
300,000
|
|
Total long-term debt
|
|
|
457,000
|
|
Stockholders Equity
|
|
$
|
1,184,204
|
|
Total capitalization
|
|
$
|
1,641,204
|
|
|
|
|
(1) |
|
In connection with our merger with Forest Energy Resources on
March 2, 2006, we amended and restated our existing secured
credit facility to, among other things, increase maximum credit
availability to $500 million for revolving loans, including
up to $50 million in letters of credit, with a
$400 million borrowing base as of that date; add an
additional dedicated $40 million letter of credit facility
that does not affect the borrowing base; and add Mariner Energy
Resources, Inc. as a co-borrower. Our credit facility was
further amended in April 2006 to increase the borrowing base to
$430 million which subsequently automatically reduced to
$362.5 million upon closing of the offering of the old
notes. We anticipate that the borrowing base will be increased
to $450 million in October 2006, subject to redetermination
or adjustment. The revolving credit facility matures on
March 2, 2010. At June 30, 2006, approximately
$161.2 million was outstanding under the revolving credit
facility, including a $4.2 million letter of credit. The
$40 million letter of credit outstanding as of
June 30, 2006 under the dedicated letter of credit facility
matures on March 2, 2009. See Managements
Discussion and Analysis of Financial Condition and Results of
Operations Credit Facility for more
information. |
44
UNAUDITED
PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
actual balance sheet information of the combined company as of
June 30, 2006 is included elsewhere in this prospectus.
The following unaudited pro forma combined statements of
operations and explanatory notes present how the combined
statements of Mariner and the Forest Gulf of Mexico operations
may have appeared had the businesses actually been combined as
of January 1, 2005.
The unaudited pro forma combined financial information has been
derived from and should be read together with the historical
consolidated financial statements of Mariner and the statements
of revenues and direct operating expenses of the Forest Gulf of
Mexico operations, which are included elsewhere in this
prospectus. The statements of revenues and direct operating
expenses of the Forest Gulf of Mexico operations do not include
all of the costs of doing business.
The unaudited pro forma combined condensed financial information
is for illustrative purposes only. The financial results may
have been different had the Forest Gulf of Mexico operations
been an independent company and had the companies always been
combined. You should not rely on the unaudited pro forma
combined condensed financial information as being indicative of
the historical results that would have been achieved had the
merger occurred in the past or the future financial results that
Mariner will achieve after the merger.
45
MARINER
ENERGY, INC.
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF
OPERATIONS
For the Six Months Ended June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy
|
|
|
|
|
|
Mariner
|
|
|
|
Mariner
|
|
|
Resources, Inc.
|
|
|
Merger
|
|
|
Pro Forma
|
|
|
|
Historical(1)
|
|
|
Historical(2)
|
|
|
Adjustments(3)
|
|
|
Combined
|
|
|
|
(In thousands, except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas sales
|
|
$
|
126,695
|
|
|
$
|
187,776
|
|
|
|
|
|
|
$
|
314,471
|
|
Other revenues
|
|
|
936
|
|
|
|
|
|
|
|
|
|
|
|
936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
127,631
|
|
|
|
187,776
|
|
|
|
|
|
|
|
315,407
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses(4)
|
|
|
19,345
|
|
|
|
34,911
|
|
|
|
|
|
|
|
54,256
|
|
Transportation expenses
|
|
|
1,527
|
|
|
|
905
|
|
|
|
|
|
|
|
2,432
|
|
General and administrative expenses
|
|
|
17,104
|
|
|
|
|
|
|
|
|
(5)
|
|
|
17,104
|
|
Depreciation, depletion and
amortization
|
|
|
46,768
|
|
|
|
|
|
|
|
89,806
|
(6)
|
|
|
136,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
84,744
|
|
|
|
35,816
|
|
|
|
89,806
|
|
|
|
210,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
42,887
|
|
|
|
151,960
|
|
|
|
(89,806
|
)
|
|
|
105,041
|
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
250
|
|
Expense, net of amounts capitalized
|
|
|
(11,139
|
)
|
|
|
|
|
|
|
(5,616
|
)(7)
|
|
|
(16,755
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
31,998
|
|
|
|
151,960
|
|
|
|
(95,422
|
)
|
|
|
88,536
|
|
Provision for income
taxes
|
|
|
(12,515
|
)
|
|
|
|
|
|
|
(19,788
|
)(8)
|
|
|
(32,303
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
19,483
|
|
|
$
|
151,960
|
|
|
$
|
(115,210
|
)
|
|
$
|
56,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share basic
|
|
$
|
0.58
|
|
|
|
|
|
|
|
|
|
|
$
|
0.67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share diluted
|
|
$
|
0.56
|
|
|
|
|
|
|
|
|
|
|
$
|
0.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding basic
|
|
|
33,640,018
|
|
|
|
|
|
|
|
50,637,010
|
|
|
|
84,277,028
|
|
Weighted average shares
outstanding diluted
|
|
|
34,749,009
|
|
|
|
|
|
|
|
50,656,160
|
|
|
|
85,405,169
|
|
46
MARINER
ENERGY, INC.
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF
OPERATIONS
For the Year Ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy
|
|
|
|
|
|
Mariner
|
|
|
|
Mariner
|
|
|
Resources, Inc.
|
|
|
Merger
|
|
|
Pro Forma
|
|
|
|
Historical(1)
|
|
|
Historical(2)
|
|
|
Adjustments(3)
|
|
|
Combined
|
|
|
|
(In thousands, except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas sales
|
|
$
|
196,122
|
|
|
$
|
392,272
|
|
|
$
|
|
|
|
$
|
588,394
|
|
Other revenues
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
199,710
|
|
|
|
392,272
|
|
|
|
|
|
|
|
591,982
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses(4)
|
|
|
29,882
|
|
|
|
80,739
|
|
|
|
|
|
|
|
110,621
|
|
Transportation expenses
|
|
|
2,336
|
|
|
|
3,383
|
|
|
|
|
|
|
|
5,719
|
|
General and administrative expenses
|
|
|
37,053
|
|
|
|
|
|
|
|
|
(5)
|
|
|
37,053
|
|
Depreciation, depletion and
amortization
|
|
|
59,426
|
|
|
|
|
|
|
|
270,390
|
(6)
|
|
|
329,816
|
|
Impairment of production equipment
held for use
|
|
|
1,845
|
|
|
|
|
|
|
|
|
|
|
|
1,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
130,542
|
|
|
|
84,122
|
|
|
|
270,390
|
|
|
|
485,054
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
69,168
|
|
|
|
308,150
|
|
|
|
(270,390
|
)
|
|
|
106,928
|
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
779
|
|
|
|
|
|
|
|
|
|
|
|
779
|
|
Expense, net of amounts capitalized
|
|
|
(8,172
|
)
|
|
|
|
|
|
|
(10,378
|
)(9)
|
|
|
(18,550
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
61,775
|
|
|
|
308,150
|
|
|
|
(280,768
|
)
|
|
|
89,157
|
|
Provision for income
taxes
|
|
|
(21,294
|
)
|
|
|
|
|
|
|
(9,911
|
)(8)
|
|
|
(31,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
40,481
|
|
|
$
|
308,150
|
|
|
$
|
(290,679
|
)
|
|
$
|
57,952
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share basic
|
|
$
|
1.24
|
|
|
|
|
|
|
|
|
|
|
$
|
0.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share diluted
|
|
$
|
1.20
|
|
|
|
|
|
|
|
|
|
|
$
|
0.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding basic
|
|
|
32,667,582
|
|
|
|
|
|
|
|
50,637,010
|
|
|
|
83,304,592
|
|
Weighted average shares
outstanding diluted
|
|
|
33,766,577
|
|
|
|
|
|
|
|
50,687,850
|
|
|
|
84,454,427
|
|
|
|
|
(1) |
|
The historical Mariner information presented excludes activity
related to the Forest Gulf of Mexico operations as Mariner
acquired them in the merger consummated on March 2, 2006. |
|
(2) |
|
The Forest Gulf of Mexico operations historically have been
operated as part of Forests total oil and gas operations.
No historical GAAP-basis financial statements exist for the
Forest Gulf of Mexico operations on a stand-alone basis;
however, statements of revenues and direct operating expenses
are presented for the six months ended June 30, 2006 and
for the year ended December 31, 2005. |
|
(3) |
|
Transaction costs consisting of accounting, consulting and legal
fees are anticipated to be approximately $7.8 million.
These costs are directly attributable to the transaction and
have been excluded from the pro forma financial statements as
they represent material nonrecurring charges. |
|
(4) |
|
Includes production taxes. |
47
|
|
|
(5) |
|
The pro forma general and administrative expenses do not include
costs associated with the Forest Gulf of Mexico assets. Mariner
believes the overhead costs associated with these operations in
2006 will be approximately $6.4 million, net of capitalized
amounts. |
|
(6) |
|
To adjust depreciation, depletion and amortization expense to
give effect to the acquisition of the Forest Gulf of Mexico
operations and their
step-up in
value using the unit of production method under the full cost
method of accounting. |
|
(7) |
|
To adjust interest expense to give effect to the financing
activities in connection with the organization of Forest Energy
Resources assuming an interest rate of 6.375% based on the terms
of the senior bank credit facility obtained by Forest Energy
Resources. The interest rates used are
30-day LIBOR
plus 1.50%, or 6.375%, as of June 30, 2006. A change in
interest rates of approximately 10% would result in a change in
pro forma combined interest of approximately $0.6 million
for the six months ended June 30, 2006. |
|
(8) |
|
To record income tax expense on the combined company results of
operations based on a statutory combined federal and state tax
rate of 36.5%. |
|
(9) |
|
To adjust interest expense to give effect to the financing
activities in connection with the organization of Forest Energy
Resources assuming an interest rate of 5.89% for the year ended
December 31, 2005 based on the terms of the senior term
loan facility obtained by Forest Energy Resources. The interest
rates used are
30-day LIBOR
plus 1.50%, or 5.89% as of December 31, 2005. A change in
interest rates of approximately 10% would result in a change in
pro forma combined interest expense of approximately
$1.0 million for the year ended December 31, 2005. |
Supplemental
Pro Forma Combined Oil and Gas Reserve and Standardized Measure
Information (Unaudited)
The following unaudited supplemental pro forma oil and natural
gas reserve tables present how the combined oil and gas reserve
and standardized measure information of Mariner and the Forest
Gulf of Mexico operations may have appeared had the businesses
actually been combined as of January 1, 2005. The
combination of the Forest Gulf of Mexico operations with
Mariners operations is expected to cause the average
reserve life of Mariners oil and gas properties to
decrease from current levels and to result in a higher rate of
depreciation, depletion, and amortization for the combined
operations. For example, the estimated proved reserves of the
Forest Gulf of Mexico properties as of December 31, 2005
were 306.1 Bcfe and production for the year ended
December 31, 2005 was approximately 65.8 Bcfe, a
reserve life on an annualized basis of 4.7. This ratio is
indicative of the relatively higher productive rates of offshore
oil and gas properties when compared to most onshore fields.
While the higher productive rates generally result in a faster
return on investment than onshore fields, they also result in a
faster depletion of the underlying proved reserves and a
corresponding higher rate of depreciation, depletion, and
amortization. As of December 31, 2005, Mariners
proved reserves totaled 337.6 Bcfe and production for the
year ended December 31, 2005 was approximately
29.1 Bcfe, a reserve life on an annualized basis of 11.6.
For the combined operations, as of December 31, 2005,
proved reserves would have totaled approximately 643.7 Bcfe
and production for the year ended December 31, 2005 would
have totaled 94.9 Bcfe, a reserve life on an annualized
basis of 6.8. The Supplemental Pro Forma Combined Oil and Gas
Reserve and Standardized Measure Information is for illustrative
purposes only. You should refer to footnote 10 in
Mariners Notes to the Financial Statements on
page F-54
and footnote 3 in Forests Gulf of Mexico Operations
Notes to Statements of Revenues and Direct Operating Expenses
for additional information presented in accordance with the
requirements of Statement of Financial Accounting Standards
No. 69, Disclosures About Oil and Gas Producing Activities.
48
ESTIMATED
PRO FORMA COMBINED QUANTITIES OF PROVED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy Resources, Inc.
|
|
|
|
|
|
|
Mariner Historical
|
|
|
Historical
|
|
|
Mariner Pro Forma Combined
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Equivalent
|
|
|
Liquids
|
|
|
Gas
|
|
|
Equivalent
|
|
|
Liquids
|
|
|
Gas
|
|
|
Equivalent
|
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
(MMcfe)
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
(MMcfe)
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
(MMcfe)
|
|
|
December 31, 2004
|
|
|
14,255
|
|
|
|
151,933
|
|
|
|
237,465
|
|
|
|
11,650
|
|
|
|
269,808
|
|
|
|
339,708
|
|
|
|
25,905
|
|
|
|
421,741
|
|
|
|
577,173
|
|
Revisions of previous estimates
|
|
|
835
|
|
|
|
963
|
|
|
|
5,971
|
|
|
|
3,123
|
|
|
|
4,815
|
|
|
|
23,553
|
|
|
|
3,958
|
|
|
|
5,778
|
|
|
|
29,524
|
|
Extensions, discoveries and other
additions
|
|
|
1,167
|
|
|
|
22,307
|
|
|
|
29,309
|
|
|
|
504
|
|
|
|
5,639
|
|
|
|
8,663
|
|
|
|
1,671
|
|
|
|
27,946
|
|
|
|
37,972
|
|
Production
|
|
|
(1,791
|
)
|
|
|
(18,354
|
)
|
|
|
(29,100
|
)
|
|
|
(2,783
|
)
|
|
|
(49,120
|
)
|
|
|
(65,818
|
)
|
|
|
(4,574
|
)
|
|
|
(67,474
|
)
|
|
|
(94,918
|
)
|
Purchases of reserves in place
|
|
|
7,181
|
|
|
|
50,837
|
|
|
|
93,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,181
|
|
|
|
50,837
|
|
|
|
93,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
21,647
|
|
|
|
207,686
|
|
|
|
337,568
|
|
|
|
12,494
|
(1)
|
|
|
231,142
|
|
|
|
306,106
|
(1)
|
|
|
34,141
|
|
|
|
438,828
|
|
|
|
643,674
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes 3,223 Mbbls of natural gas liquids. |
ESTIMATED
PRO FORMA COMBINED QUANTITIES OF PROVED DEVELOPED
RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy Resources, Inc.
|
|
|
|
|
Mariner Historical
|
|
Historical
|
|
Mariner Pro Forma Combined
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
Natural
|
|
Gas
|
|
|
|
Natural
|
|
Gas
|
|
|
|
Natural
|
|
Gas
|
|
|
Oil
|
|
Gas
|
|
Equivalent
|
|
Liquids
|
|
Gas
|
|
Equivalent
|
|
Liquids
|
|
Gas
|
|
Equivalent
|
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcfe)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcfe)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcfe)
|
|
December 31, 2005
|
|
|
9,564
|
|
|
|
110,011
|
|
|
|
167,395
|
|
|
|
8,792
|
|
|
|
142,143
|
|
|
|
194,895
|
|
|
|
18,356
|
|
|
|
252,154
|
|
|
|
362,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
PRO FORMA
COMBINED STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31, 2005
|
|
|
|
|
|
|
Forest Energy
|
|
|
Mariner
|
|
|
|
Mariner
|
|
|
Resources, Inc.
|
|
|
Pro Forma
|
|
|
|
Historical
|
|
|
Historical
|
|
|
Combined
|
|
|
Future cash inflows
|
|
$
|
3,451,321
|
|
|
$
|
2,849,998
|
|
|
$
|
6,301,319
|
|
Future production costs
|
|
|
(687,583
|
)
|
|
|
(226,248
|
)
|
|
|
(913,831
|
)
|
Future development costs
|
|
|
(386,497
|
)
|
|
|
(386,855
|
)
|
|
|
(773,352
|
)
|
Future income taxes
|
|
|
(695,921
|
)
|
|
|
(649,002
|
)
|
|
|
(1,344,923
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
1,681,320
|
|
|
|
1,587,893
|
|
|
|
3,269,213
|
|
Discount of future net cash flows
at 10% per annum
|
|
|
(774,755
|
)
|
|
|
(292,730
|
)
|
|
|
(1,067,485
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
906,565
|
|
|
$
|
1,295,163
|
|
|
$
|
2,201,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of period
|
|
$
|
494,382
|
|
|
$
|
925,837
|
|
|
$
|
1,420,219
|
|
Increase (decrease) in discounted
future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas
produced, net of production costs
|
|
|
(213,189
|
)
|
|
|
(436,385
|
)
|
|
|
(649,574
|
)
|
Net changes in prices and
production costs
|
|
|
425,317
|
|
|
|
692,164
|
|
|
|
1,117,481
|
|
Extensions and discoveries, net of
future development and production costs
|
|
|
119,501
|
|
|
|
53,744
|
|
|
|
173,245
|
|
Purchases of reserves in place
|
|
|
189,782
|
|
|
|
|
|
|
|
189,782
|
|
Development costs during period
and net change in development costs
|
|
|
46,632
|
|
|
|
7,022
|
|
|
|
53,654
|
|
Revision of previous quantity
estimates
|
|
|
16,323
|
|
|
|
109,207
|
|
|
|
125,530
|
|
Net change in income taxes
|
|
|
(201,647
|
)
|
|
|
(178,643
|
)
|
|
|
(380,290
|
)
|
Accretion of discount before
income taxes
|
|
|
49,438
|
|
|
|
122,217
|
|
|
|
171,655
|
|
Changes in production rates
(timing) and other
|
|
|
(19,974
|
)
|
|
|
|
|
|
|
(19,974
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of period
|
|
$
|
906,565
|
|
|
$
|
1,295,163
|
|
|
$
|
2,201,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
SELECTED
HISTORICAL FINANCIAL INFORMATION FOR MARINER
The following table shows Mariners summary historical
consolidated financial data as of and for the six months ended
June 30, 2006 and June 30, 2005, the year ended
December 31, 2005, the period from January 1, 2004
through March 2, 2004, the period from March 3, 2004
through December 31, 2004, and each of the three years
ended December 31, 2003. The summary historical
consolidated financial data for the year ended December 31,
2005, the period from January 1, 2004 through March 2,
2004, the period from March 3, 2004 through
December 31, 2004, and the year ended December 31,
2003 are derived from Mariners audited financial
statements included herein, and the historical consolidated
financial data as of and for the two years ended
December 31, 2002 are derived from Mariners audited
financial statements that are not included herein. The summary
historical consolidated financial data for the six months ended
June 30, 2006 and the six months ended June 30, 2005
has been derived from Mariners unaudited financial
statements. You should read the following data in connection
with Managements Discussion and Analysis of
Financial Condition and Results of Operations, and the
consolidated financial statements included elsewhere in this
prospectus, where there is additional disclosure regarding the
information in the following table, including pro forma
information regarding the merger with Forest Energy Resources.
Mariners historical results are not necessarily indicative
of results to be expected in future periods.
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
the financial information as of June 30, 2006 below
includes the Forest Gulf of Mexico operations as of and after
March 2, 2006.
On March 2, 2004, Mariners former indirect parent,
Mariner Energy LLC, merged with MEI Acquisitions, LLC, an
affiliate of the private equity funds, Carlyle/Riverstone Global
Energy and Power Fund II, L.P. and ACON Investments LLC.
The financial information contained herein is presented in the
style of Post-2004 Merger activity (for the March 3, 2004
through December 31, 2004 period, the year ended
December 31, 2005 and the six months ended June 30,
2006 and June 30, 2005) and Pre-2004 Merger activity
(for all periods prior to March 2, 2004) to reflect
the impact of the restatement of assets and liabilities to fair
value as required by push-down purchase accounting
at the March 2, 2004 merger date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(1)
|
|
$
|
247.9
|
|
|
$
|
107.6
|
|
|
$
|
199.7
|
|
|
$
|
174.4
|
|
|
|
$
|
39.8
|
|
|
$
|
142.5
|
|
|
$
|
158.2
|
|
|
$
|
155.0
|
|
Lease operating expenses
|
|
|
37.6
|
|
|
|
13.2
|
|
|
|
29.9
|
|
|
|
21.4
|
|
|
|
|
4.1
|
|
|
|
24.7
|
|
|
|
26.1
|
|
|
|
20.1
|
|
Transportation expenses
|
|
|
2.3
|
|
|
|
1.5
|
|
|
|
2.3
|
|
|
|
1.9
|
|
|
|
|
1.1
|
|
|
|
6.3
|
|
|
|
10.5
|
|
|
|
12.0
|
|
Depreciation, depletion and
amortization
|
|
|
109.8
|
|
|
|
31.1
|
|
|
|
59.4
|
|
|
|
54.3
|
|
|
|
|
10.6
|
|
|
|
48.3
|
|
|
|
70.8
|
|
|
|
63.5
|
|
Impairment of production equipment
held for use
|
|
|
|
|
|
|
|
|
|
|
1.8
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
Impairment of Enron related
receivables
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
29.5
|
|
General and administrative expenses
|
|
|
17.4
|
|
|
|
15.4
|
|
|
|
37.1
|
|
|
|
7.6
|
|
|
|
|
1.1
|
|
|
|
8.1
|
|
|
|
7.7
|
|
|
|
9.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
80.8
|
|
|
|
46.4
|
|
|
|
69.2
|
|
|
|
88.2
|
|
|
|
|
22.9
|
|
|
|
51.9
|
|
|
|
39.9
|
|
|
|
20.6
|
|
Interest income
|
|
|
0.3
|
|
|
|
0.6
|
|
|
|
0.8
|
|
|
|
0.2
|
|
|
|
|
0.1
|
|
|
|
0.8
|
|
|
|
0.4
|
|
|
|
0.7
|
|
Interest expense
|
|
|
(14.7
|
)
|
|
|
(3.6
|
)
|
|
|
(8.2
|
)
|
|
|
(6.0
|
)
|
|
|
|
|
|
|
|
(7.0
|
)
|
|
|
(10.3
|
)
|
|
|
(8.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
66.4
|
|
|
|
43.4
|
|
|
|
61.8
|
|
|
|
82.4
|
|
|
|
|
23.0
|
|
|
|
45.7
|
|
|
|
30.0
|
|
|
|
12.4
|
|
Provision for income taxes
|
|
|
(24.6
|
)
|
|
|
(14.8
|
)
|
|
|
(21.3
|
)
|
|
|
(28.8
|
)
|
|
|
|
(8.1
|
)
|
|
|
(9.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
Income before cumulative
effect of change in accounting method net of tax effects
|
|
$
|
41.8
|
|
|
$
|
28.6
|
|
|
$
|
40.5
|
|
|
$
|
53.6
|
|
|
|
$
|
14.9
|
|
|
$
|
36.3
|
|
|
$
|
30.0
|
|
|
$
|
12.4
|
|
Income before cumulative effect
per common unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
0.62
|
|
|
|
0.90
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
0.50
|
|
|
$
|
1.22
|
|
|
$
|
1.01
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
0.62
|
|
|
|
0.89
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.22
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Cumulative effect of changes in
accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
41.8
|
|
|
$
|
28.6
|
|
|
$
|
40.5
|
|
|
$
|
53.6
|
|
|
|
$
|
14.9
|
|
|
$
|
38.2
|
|
|
$
|
30.0
|
|
|
$
|
12.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.62
|
|
|
$
|
0.90
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
0.50
|
|
|
$
|
1.29
|
|
|
$
|
1.01
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
0.62
|
|
|
|
0.89
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.29
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Capital Expenditure and
Disposal Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, including
leasehold/seismic
|
|
|
138.7
|
|
|
|
7.5
|
|
|
$
|
60.9
|
|
|
$
|
40.4
|
|
|
|
$
|
7.5
|
|
|
$
|
31.6
|
|
|
$
|
40.4
|
|
|
$
|
66.3
|
|
Development and other
|
|
|
134.2
|
|
|
|
72.0
|
|
|
|
191.8
|
|
|
|
93.2
|
|
|
|
|
7.8
|
|
|
|
51.7
|
|
|
|
65.7
|
|
|
|
98.2
|
|
Proceeds from property conveyances
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6
|
)
|
|
|
(52.3
|
)
|
|
|
(90.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures net of
proceeds from property conveyances
|
|
$
|
270.9
|
|
|
$
|
79.5
|
|
|
$
|
252.7
|
|
|
$
|
133.6
|
|
|
|
$
|
15.3
|
|
|
$
|
(38.3
|
)
|
|
$
|
53.8
|
|
|
$
|
74.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes effects of hedging. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2001
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net, full
cost method
|
|
$
|
1,913.6
|
|
|
$
|
351.3
|
|
|
$
|
515.9
|
|
|
$
|
303.8
|
|
|
|
$
|
207.9
|
|
|
$
|
287.6
|
|
|
$
|
290.6
|
|
Total assets
|
|
|
2,457.1
|
|
|
|
463.1
|
|
|
|
665.5
|
|
|
|
376.0
|
|
|
|
|
312.1
|
|
|
|
360.2
|
|
|
|
363.9
|
|
Long-term debt, less current
maturities
|
|
|
457.0
|
|
|
|
99.0
|
|
|
|
156.0
|
|
|
|
115.0
|
|
|
|
|
|
|
|
|
99.8
|
|
|
|
99.8
|
|
Stockholders equity
|
|
|
1,184.2
|
|
|
|
201.0
|
|
|
|
213.3
|
|
|
|
133.9
|
|
|
|
|
218.2
|
|
|
|
170.1
|
|
|
|
180.1
|
|
Working capital (deficit)(2)
|
|
|
(100.8
|
)
|
|
|
18.3
|
|
|
|
(46.4
|
)
|
|
|
(18.7
|
)
|
|
|
|
38.3
|
|
|
|
(24.4
|
)
|
|
|
(19.6
|
)
|
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratio of Earnings to Fixed
Charges(3)
|
|
|
5.25
|
|
|
|
12.54
|
|
|
|
7.88
|
|
|
|
17.17
|
|
|
|
|
6.83
|
|
|
|
3.56
|
|
|
|
1.82
|
|
|
|
|
(1) |
|
Balance sheet data as of June 30, 2006 reflects
consolidation of the assets of the Forest Gulf of Mexico
operations as of March 2, 2006. Balance sheet data as of
December 31, 2004 reflects purchase accounting adjustments
to oil and gas properties, total assets and stockholders
equity resulting from the acquisition of our former indirect
parent on March 2, 2004. |
52
|
|
|
(2) |
|
Working capital (deficit) excludes current derivative assets and
liabilities, deferred tax assets and restricted cash. |
|
(3) |
|
For the purposes of determining the ratio of earnings to fixed
charges, earnings consist of the sum of income before taxes,
plus fixed charges, less capitalized interest, and fixed charges
consist of interest expense (net of capitalized interest), plus
capitalized interest, plus amortized discounts related to
indebtedness. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
190.6
|
|
|
$
|
77.5
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Net cash provided by operating
activities
|
|
|
96.1
|
|
|
|
72.7
|
|
|
|
165.4
|
|
|
|
135.2
|
|
|
|
|
20.3
|
|
|
|
88.9
|
|
|
|
60.3
|
|
|
|
113.5
|
|
Net cash (used) provided by
investing activities
|
|
|
(204.8
|
)
|
|
|
(98.7
|
)
|
|
|
(247.8
|
)
|
|
|
(133.0
|
)
|
|
|
|
(15.3
|
)
|
|
|
52.9
|
|
|
|
(53.8
|
)
|
|
|
(74.0
|
)
|
Net cash (used) provided by
financing activities
|
|
|
109.8
|
|
|
|
31.5
|
|
|
|
84.4
|
|
|
|
64.9
|
|
|
|
|
|
|
|
|
(100.0
|
)
|
|
|
|
|
|
|
(30.0
|
)
|
Reconciliation of
Non-GAAP Measures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
190.6
|
|
|
$
|
77.5
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Changes in working capital
|
|
|
(93.6
|
)
|
|
|
(14.9
|
)
|
|
|
20.0
|
|
|
|
6.2
|
|
|
|
|
(13.2
|
)
|
|
|
7.2
|
|
|
|
(20.4
|
)
|
|
|
7.5
|
|
Non-cash hedge loss(2)
|
|
|
(3.5
|
)
|
|
|
(2.5
|
)
|
|
|
(4.5
|
)
|
|
|
(7.9
|
)
|
|
|
|
|
|
|
|
(2.0
|
)
|
|
|
(23.2
|
)
|
|
|
|
|
Amortization/other
|
|
|
9.1
|
|
|
|
6.1
|
|
|
|
1.2
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
0.6
|
|
Stock compensation expense
|
|
|
7.9
|
|
|
|
9.5
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(14.4
|
)
|
|
|
(3.0
|
)
|
|
|
(7.4
|
)
|
|
|
(5.8
|
)
|
|
|
|
0.1
|
|
|
|
(6.2
|
)
|
|
|
(9.9
|
)
|
|
|
(8.2
|
)
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.6
|
)
|
|
|
|
|
|
|
|
(10.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
$
|
96.1
|
|
|
$
|
72.7
|
|
|
$
|
165.4
|
|
|
$
|
135.2
|
|
|
|
$
|
20.3
|
|
|
$
|
88.9
|
|
|
$
|
60.3
|
|
|
$
|
113.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
EBITDA means earnings before interest, income taxes,
depreciation, depletion and amortization and impairments. For
the six months ended June 30, 2006 and 2005, EBITDA
includes $7.9 million and $9.5 million, respectively,
in non-cash compensation expense related to restricted stock and
stock options. For the year ended December 31, 2005, EBITDA
includes $25.7 million in non-cash compensation expense
related to restricted stock and stock options granted in 2005.
We believe that EBITDA is a widely accepted financial indicator
that provides additional information about our ability to meet
our future requirements for debt service, capital expenditures
and working capital, but EBITDA should not be considered in
isolation or as a substitute for net income, operating income,
net cash provided by operating activities or any other measure
of financial performance presented in accordance with generally
accepted accounting principles or as a measure of a
companys profitability or liquidity. |
|
(2) |
|
In accordance with SFAS No. 133 Accounting for
Derivative Instruments and Hedging Activities, as amended
by SFAS No. 137 and No. 138, we de-designated our
contracts effective December 2, 2001 after the counterparty
(an affiliate of Enron Corp.) filed for bankruptcy and
recognized all market value changes subsequent to such
de-designation in our earnings. The value recorded up to the
time of dedesignation and included in Accumulated Other
Comprehensive Income (AOCI), has reversed out of
AOCI and into earnings as the original corresponding production,
as hedged by the contracts, is produced. In accordance with
purchase price accounting implemented at the time of the merger
of our former indirect parent on March 2, 2004, we recorded
the mark to market liability of our hedge contracts at such date
totaling $12.4 million as a liability on our balance sheet.
The value at the time of the merger and included in AOCI has
reversed out of AOCI and into earnings as the original
corresponding production, as hedged by the contracts, is
produced. We have designated subsequent hedge contracts as cash
flow hedges with gains and losses resulting from the
transactions recorded at market value in AOCI, as appropriate,
until recognized as operating income in our Statement of
Operations as the physical production hedged by the contracts is
delivered. |
53
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are an independent oil and natural gas exploration,
development and production company with principal operations in
the Gulf of Mexico and West Texas. In the Gulf of Mexico, our
areas of operation include the deepwater and the shelf area. We
have been active in the Gulf of Mexico and West Texas since the
mid-1980s. As a result of increased drilling of shelf prospects,
the acquisition of Forests Gulf of Mexico assets located
primarily on the shelf, and development activities in West
Texas, we have evolved from a company with primarily a deepwater
focus to one with a balance of exploitation and exploration of
the Gulf of Mexico deepwater and shelf, and longer-lived West
Texas properties. As of December 31, 2005 (after giving
effect to the merger transaction with Forest Energy Resources),
approximately 56% of our proved reserves were classified as
proved developed, with approximately 32% of the reserves located
in West Texas, 19% in the Gulf of Mexico deepwater and 49% on
the Gulf of Mexico shelf.
On March 2, 2004, Mariners former indirect parent,
Mariner Energy LLC, merged with MEI Acquisitions, LLC, an
affiliate of the private equity funds, Carlyle/Riverstone Global
Energy and Power Fund II, L.P. and ACON Investments LLC.
Prior to the merger, we were owned indirectly by JEDI, which was
an indirect wholly-owned subsidiary of Enron Corp. The gross
merger consideration was $271.1 million (which excludes
$7.0 million of acquisition costs and other expenses paid
directly by Mariner), $100 million of which was provided as
equity by our new owners. As a result of the merger, we are no
longer affiliated with Enron Corp. See Enron
Related Matters. The merger did not result in a change in
our strategic direction or operations. The financial information
contained herein is presented in the style of Pre-2004 Merger
activity (for all periods prior to March 2, 2004) and
Post-2004 Merger activity (for the March 3, 2004 through
December 31, 2004 period) to reflect the impact of the
restatement of assets and liabilities to fair value as required
by push-down purchase accounting at the
March 2, 2004 merger date. The application of push-down
accounting had no effect on our 2004 results of operations other
than immaterial increases in depreciation, depletion and
amortization expense and interest expense and a related decrease
in our provision for income taxes. To facilitate
managements discussion and analysis of financial condition
and results of operations, we have presented 2004 financial
information as Pre-2004 Merger (for the January 1 through
March 2, 2004 period), Post-2004 Merger (for the
March 3, 2004 through December 31, 2004 period) and
Combined (for the full period from January 1 through
December 31, 2004). The combined presentation does not
reflect the adjustments to our statement of operations that
would be reflected in a pro forma presentation. However, because
such adjustments are not material, we believe that our combined
presentation presents a fair presentation and facilitates an
understanding of our results of operations.
In March 2005, we completed a private placement of
16,350,000 shares of our common stock to qualified
institutional buyers,
non-U.S. persons
and accredited investors, which generated approximately
$229 million of gross proceeds, or approximately
$211 million net of initial purchasers discount,
placement fee and offering expenses. Our former sole
stockholder, MEI Acquisitions Holdings, LLC, also sold
15,102,500 shares of our common stock in the private
placement. We used $166 million of the net proceeds from
the sale of 12,750,000 shares of common stock to purchase
and retire an equal number of shares of our common stock from
our former sole stockholder. We used $38 million of the
remaining net proceeds of approximately $44 million to
repay borrowings drawn on our credit facility, and the balance
to pay down $6 million of a $10 million promissory
note payable to JEDI. See Enron Related
Matters. As a result, after the private placement, an
affiliate of MEI Acquisitions Holdings, LLC beneficially owned
approximately 5.3% of our outstanding common stock.
Our revenues, profitability and future growth depend
substantially on prevailing prices for oil and gas and our
ability to find, develop and acquire oil and gas reserves that
are economically recoverable while controlling and reducing
costs. The energy markets have historically been very volatile.
Commodity prices are currently at or near historical highs and
may fluctuate significantly in the future. Although we attempt
to mitigate the impact of price declines and provide for more
predictable cash flows through our hedging strategy, a
substantial or extended decline in oil and natural gas prices or
poor drilling results could have a
54
material adverse effect on our financial position, results of
operations, cash flows, quantities of natural gas and oil
reserves that we can economically produce and our access to
capital. Conversely, the use of derivative instruments also can
prevent us from realizing the full benefit of upward price
movements.
Recent
Developments
Forest Gulf of Mexico Merger. On March 2,
2006, a subsidiary of Mariner completed a merger transaction
with Forest Energy Resources. Prior to the consummation of the
merger, Forest transferred and contributed the assets and
certain liabilities associated with its Gulf of Mexico
operations to Forest Energy Resources. Immediately prior to the
merger, Forest distributed all of the outstanding shares of
Forest Energy Resources to Forest shareholders on a pro rata
basis. Forest Energy Resources then merged with a newly-formed
subsidiary of Mariner, became a new wholly-owned subsidiary of
Mariner, and changed its name to Mariner Energy Resources, Inc.
Immediately following the merger, approximately 59% of Mariner
common stock was held by shareholders of Forest and
approximately 41% of Mariner common stock was held by the
pre-merger stockholders of Mariner. In the merger, Mariner
issued 50,637,010 shares of common stock to Forest
shareholders. Our acquisition of Forest Energy Resources added
approximately 306 Bcfe of estimated proved reserves as of
December 31, 2005, of which 76% were natural gas and 24%
were oil and condensate.
West Cameron Acquisition. In August 2006, we
acquired the interest of BP Exploration and Production Inc.,
which we refer to as BP, in West Cameron
Block 110 and the southeast quarter of West Cameron
Block 111 in the Gulf of Mexico. The interest was acquired
by our subsidiary, Mariner Energy Resources, Inc., exercising
its preferential right to purchase. BP retained its interest in
depths below 15,000 feet. In the Forest merger, we acquired
Forest Energy Resources 37.5% interest in the properties.
As a result of the August 2006 acquisition, Mariner Energy
Resources, Inc. now owns 100% of the working interest, exclusive
of the deep rights retained by BP, and Mariner Energy, Inc.
became operator of the interests owned by its subsidiary. The
acquisition cost, net of preliminary purchase price adjustments,
was approximately $70.9 million, which was financed by
borrowing under our senior secured credit facility. A
$10.4 million letter of credit under our senior secured
credit facility also was issued in favor of BP to secure
plugging and abandonment obligations. The acquisition adds
proved reserves estimated by us to be 20 Bcfe as of
August 1, 2006. Production associated with the acquired
interest was approximately 11 MMcfe/day during July 2006.
Material Gulf of Mexico Discovery. In October
2006, we announced that we made a material conventional shelf
discovery in the High Island 116 #5ST1 well, drilled
to a total measured depth of 14,683 feet / 13,150 feet
true vertical depth. The well encountered approximately
540 feet of net true vertical depth pay in thirteen sands.
We anticipate completion and initial production in the fourth
quarter of 2006. High Island 116 is part of the Forest Gulf of
Mexico operations we acquired in March 2006. We have a 100%
working interest and an approximate 72% net revenue interest in
the well.
Effects of the 2005 Hurricane Season. In 2005,
our operations were adversely affected by one of the most active
and severe hurricane seasons in recorded history, resulting in
shut-in production and startup delays. We estimate that as of
September 30, 2006, approximately 12 MMcfe per day of
production remained shut-in and approximately 33 MMcfe per
day of production had recommenced since June 30, 2006. The
four deepwater projects that experienced startup delays have
recommenced production. As a result of ongoing repairs to
pipelines, facilities, terminals and host facilities, we expect
most of the remaining shut-in production to recommence by the
end of 2006 and the balance in 2007, except that an immaterial
amount of production is not expected to recommence.
We estimate that the costs to repair damage caused by the
hurricanes to our platforms and facilities will be approximately
$80 million. However, until we are able to complete all of
the repair work, this estimate is subject to significant
variance. For the insurance period covering the 2005 hurricane
activity, we carried a $3 million annual deductible and a
$0.5 million single occurrence deductible for the Mariner
assets. Insurance covering the Forest Gulf of Mexico properties
carried a $5 million deductible for each occurrence. Until
the repairs are completed and we submit costs to our insurance
underwriters for their review, the full extent of our insurance
recoveries and the resulting net costs to us for Hurricanes
Katrina and Rita will be unknown. However, we expect the total
costs not covered by the combined insurance policies to be less
than $15 million.
55
2006
Highlights
For the six months ended June 30, 2006, we recognized net
income of $41.8 million on total revenues of
$247.9 million compared to net income of $28.6 million
on total revenues of $107.6 million for the six months
ended June 30, 2005. Production, revenues and net income
increased significantly from results reported a year ago
primarily as a result of consolidation as of March 2, 2006
of assets acquired in the merger transaction with Forest Energy
Resources. Production for the first six months of 2006 averaged
176 MMcfe per day (31.8 Bcfe total for the period),
compared to average daily production of 91 MMcfe per day
for the first six months of 2005 (16.5 Bcfe total for the
period). Production for the first six months of 2006 continued
to be adversely effected by the 2005 hurricane season.
2005
Highlights
During the year ended December 31, 2005, we recognized net
income of $40.5 million on total revenues of
$199.7 million compared to net income of $68.4 million
on total revenues of $214.2 million in 2004. Net income
decreased 41% compared to 2004, primarily due to recognizing
$25.7 million of stock compensation expense in 2005, and a
23% decrease in production, partially offset by a 35%
improvement in net commodity prices realized by us (before the
effects of hedging.) Our 2005 results were also negatively
impacted by increased hedging losses of $49.3 million in
2005 compared to a $19.8 million loss in 2004. We produced
approximately 29.1 Bcfe during 2005 and our average daily
production rate was 80 MMcfe compared to 37.6 Bcfe, or
103 MMcfe per day, for 2004. Production during the last two
quarters of 2005 was negatively impacted by the effects of the
2005 hurricane season. We invested approximately
$252.7 million in total capital in 2005 compared to
$148.9 million in 2004.
Our 2005 results reflect the private placement of an additional
3.6 million shares of stock in March 2005. The net proceeds
of approximately $44 million generated by the private
placement were used to repay existing debt. We also granted
2,267,270 shares of restricted stock and options to
purchase 809,000 shares of stock in 2005 and recorded
compensation expense of $25.7 million in 2005 related to
the restricted stock and options.
2004
Highlights
We recognized net income of $68.4 million in 2004 compared
to net income of $38.2 million in 2003. The increase in net
income was primarily the result of improvements in operating
results, including a 13% increase in production volumes, a 21%
improvement in the net commodity prices realized by us (before
the effects of hedging) and an 8% decrease in lease operating
expenses and transportation expenses on a per unit basis. These
improvements were partially offset by an 8% increase in general
and administrative expenses and a 34% increase in depreciation,
depletion, and amortization expenses. Our hedging results also
improved by $9.7 million to a $19.8 million loss, from
a $29.5 million loss in the prior year. In addition, we
recorded income tax expenses of $36.9 million in 2004
compared to $9.4 million in 2003.
We invested approximately $148.9 million in total capital
in 2004 compared to $83.3 million in 2003.
During 2004, we increased our proved reserves by approximately
69 Bcfe, bringing estimated proved reserves as of
December 31, 2004 to approximately 237.5 Bcfe after
2004 production of 37.6 Bcfe.
We had $2.5 million and $60.2 million in cash and cash
equivalents as of December 31, 2004 and December 31,
2003, respectively.
Production
For the first six months of 2006, our production averaged
125 MMcf of natural gas per day and approximately
8,400 barrels of oil per day, or a total of approximately
176 MMcfe per day. Natural gas production comprised
approximately 71% of total production for the six months ended
June 30, 2006 compared to approximately 64% for the
comparable period in 2005. This increase in the gas to oil ratio
primarily resulted from the acquisition of the Forest Gulf of
Mexico operations. Production continued to be adversely affected
by the 2005 hurricane season, resulting in shut-in production
and startup delays. We estimate that as of September 30,
2006, approximately 12 MMcfe per day of production remained
shut-in and
56
approximately 33 MMcfe per day of production had
recommenced since June 30, 2006. The four deepwater
projects that experienced startup delays have recommenced
production. As a result of ongoing repairs to pipelines,
facilities, terminals and host facilities, we expect most of the
remaining shut-in production to recommence by the end of 2006
and the balance in 2007, except that an immaterial amount of
production is not expected to recommence.
Our production for 2005 averaged approximately 50 MMcf of
natural gas per day and approximately 4,900 barrels of oil
per day, or a total of approximately 80 MMcfe per day.
Natural gas production comprised approximately 63% of total
production in 2005 and 2004.
In the last two quarters of 2005 our production was negatively
impacted by Hurricanes Katrina and Rita. Production shut-in and
deferred because of the hurricanes impact totaled
approximately 6-8 Bcfe during the last two quarters of
2005. As of December 31, 2005 approximately 5 MMcfe
per day of production remained shut-in awaiting repairs,
primarily associated with our Baccarat property, which was
brought back on-line in January 2006. While we believe physical
damage to our existing platforms and facilities was relatively
minor from both hurricanes, the effects of the storms caused
damage to onshore pipeline and processing facilities that
resulted in a portion of our production being temporarily
shut-in, or in the case of our Viosca Knoll 917 (Swordfish)
project, postponed until the fourth quarter of 2005. In
addition, Hurricane Katrina caused damage to platforms that host
three of our development projects: Mississippi Canyon 718
(Pluto), Mississippi Canyon 296 (Rigel), and Mississippi Canyon
66 (Ochre). Our Rigel project recommenced production in the
first quarter of 2006, and our Pluto and Ochre projects
recommenced production in the third quarter of 2006.
Our December 2004 total production averaged approximately
58 MMcf of natural gas per day and approximately
5,700 barrels of oil per day or total equivalents of
approximately 92 MMcfe per day. In September 2004, Mariner
incurred damage from Hurricane Ivan that affected our
Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357
fields. Production from Mississippi Canyon 357 was shut-in until
March 2005, when necessary repairs were completed and production
recommenced. It subsequently has been shut-in since Hurricane
Katrina, with production expected to recommence in the fourth
quarter of 2006 after completion of host platform repairs.
Production from Mississippi Canyon 66 (Ochre) recommenced in the
third quarter of 2006, producing at about the same net rate of
approximately 6.5 MMcfe per day as it was immediately prior
to Hurricane Ivan.
Historically, a majority of our total production has been
comprised of natural gas. We anticipate that our acquisition of
the Forest Gulf of Mexico operations will increase our
concentration in natural gas production. As a result,
Mariners revenues, profitability and cash flows will be
more sensitive to natural gas prices than to oil and condensate
prices.
Generally, our producing properties in the Gulf of Mexico will
have high initial production rates followed by steep declines.
As a result, we must continually drill for and develop new oil
and gas reserves to replace those being depleted by production.
Substantial capital expenditures are required to find and
develop these reserves. Our challenge is to find and develop
reserves at economic rates and commence production of these
reserves as quickly and efficiently as possible.
Deepwater discoveries typically require a longer lead time to
bring to productive status. Since 2001, we have made several
deepwater discoveries that are in various stages of development.
We commenced production at our Green Canyon 178 (Baccarat)
project in the third quarter of 2005. However, damage sustained
by the host facility during Hurricane Rita caused production to
be shut-in. Production recommenced in January 2006. We
recommenced production at our Swordfish project in the fourth
quarter of 2005, at our Rigel project in the first quarter of
2006 and at our Pluto project in the third quarter of 2006. We
currently anticipate recommencing production in the fourth
quarter of 2006 at our Ewing Banks 921 (North Black Widow)
project. Uncertainties, including scheduling, weather, and
construction lead times, could cause further delays in the
start-up of
any one of the projects.
57
Oil and
Gas Property Costs
Of the total $272.9 million of capital expenditures
incurred in the first six months of 2006, approximately
$126.1 million or 46% related to development activities (of
which about $24.0 million was onshore), $138.7 million
or 51% related to exploration activities, including the
acquisition of leasehold and seismic, and the balance of
approximately $8.1 million or 3% related to capitalized
expenses and minor corporate items.
In 2005, we incurred approximately $242.6 million in
capital costs related to property acquisitions, exploration, and
development activities and approximately $10.1 million for
capital costs associated with the installation of our Aldwell
unit gathering system and other minor corporate items. Of the
total $252.7 million of capital expenditures incurred in
2005, approximately 51% related to development activities and
capitalized overhead and interest, 24% for exploration
activities, including the acquisition of leasehold and seismic,
21% for property acquisitions, and the balance was associated
with the Aldwell Unit gathering system and minor corporate
items. Of the $121.7 million incurred on development
activities and capitalized overhead and interest, approximately
27% were for onshore operations, 69% for deep water operations,
and 4% for shelf Gulf of Mexico operations. Expenditures for
property acquisitions included $46.1 million for assets
located in West Texas and $7.9 million to acquire
additional interests in offshore Gulf of Mexico projects.
During 2004, we incurred approximately $148.9 million in
capital expenditures with 60% related to development activities,
32% related to exploration activities, including the acquisition
of leasehold and seismic, and the remainder related to
acquisitions and other items (primarily capitalized overhead and
interest). We spent approximately $88.6 million in
development capital expenditures in 2004 primarily on Aldwell
Unit development and for Viosca Knoll 917 (Swordfish),
Mississippi Canyon 718 (Pluto), and West Cameron 333 (Royal
Flush) offshore projects. All capital expenditures for
exploration activities relate to offshore projects, and
approximately 30% of exploration capital expended during 2004
was for leasehold, seismic, and geological and geophysical
costs. We incurred approximately $47.9 million of
exploration capital expenditures in 2004.
Oil and
Gas Reserves
We have maintained our reserve base through exploration and
exploitation activities despite selling 44.4 Bcfe of our
reserves in 2002. Historically, we have not acquired significant
reserves through acquisition activities; however, in 2005, we
acquired 93.9 Bcfe of estimated proved reserves primarily
in West Texas. In March 2006, we acquired estimated proved
reserves of 306.1 Bcfe as a result of the merger with
Forest Energy Resources. As of December 31, 2005, Ryder
Scott estimated our net proved reserves at approximately
337.6 Bcfe, with a PV10 of approximately $1.3 billion
and a standardized measure of discounted future net cash flows
attributable to our estimated proved reserves of approximately
$906.6 million. Please see Estimated
Proved Reserves for a definition of PV10 and a
reconciliation of PV10 to the standardized measure of discounted
future net cash flows and for more information concerning our
reserve estimates.
Development activities and acquisitions in West Texas and Gulf
of Mexico deepwater divestitures have significantly changed our
reserve profile since 2002. Proved reserves as of
December 31, 2005 were comprised of 61% West Texas, 6% Gulf
of Mexico shelf and 33% Gulf of Mexico deepwater compared to 33%
West Texas, 19% Gulf of Mexico shelf and 48% Gulf of Mexico
deepwater as of December 31, 2002. Proved undeveloped
reserves were approximately 50% of total proved reserves as of
December 31, 2005. Approximately 25% of proved undeveloped
reserves were related to our West Texas Aldwell Unit, where we
had 100% development drilling success on 170 wells from
2002 through 2005. Pro forma for the merger transaction, as of
December 31, 2005, we had approximately 644 Bcfe of proved
reserves, of which 32% were in West Texas, 49% in the Gulf of
Mexico shelf and 19% in the Gulf of Mexico deepwater. Proved
undeveloped reserves were approximately 44% of total proved
reserves as of December 31, 2005 on a pro forma basis.
58
Since December 31, 1997, we have added proved undeveloped
reserves attributable to 13 deepwater projects. As of
December 31, 2005, ten of those projects have either been
converted to proved developed reserves or sold as indicated in
the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
Reserves
|
|
|
Year
|
|
|
|
Property
|
|
(Bcfe)(1)
|
|
|
Added
|
|
|
Year Converted to Proved Developed or Sold
|
|
Mississippi Canyon 718 (Pluto)(2)
|
|
|
25.1
|
|
|
|
1998
|
|
|
2000 (100% converted to
proved developed)
|
Ewing Bank 966 (Black Widow)
|
|
|
14.0
|
|
|
|
1999
|
|
|
2000 (100% converted to
proved developed)
|
Mississippi Canyon 773 (Devils
Tower)
|
|
|
28.0
|
|
|
|
2000
|
|
|
2001 (100% of Mariners
interest sold)
|
Mississippi Canyon 305 (Aconcagua)
|
|
|
19.2
|
|
|
|
2000
|
|
|
2001 (100% of Mariners
interest sold)
|
Green Canyon 472/473 (King Kong)
|
|
|
25.5
|
|
|
|
2000
|
|
|
2002 (100% converted to
proved developed)
|
Green Canyon 516 (Yosemite)
|
|
|
14.9
|
|
|
|
2001
|
|
|
2002 (100% converted to
proved developed)
|
East Breaks 579 (Falcon)
|
|
|
66.8
|
|
|
|
2001
|
|
|
2002 (50% of Mariners
interest sold) 2003 (all of Mariners remaining interest
sold)
|
Viosca Knoll 917 (Swordfish)
|
|
|
13.4
|
|
|
|
2001
|
|
|
2005 (100% converted to
proved developed)
|
Green Canyon 178 (Baccarat)
|
|
|
4.0
|
|
|
|
2004
|
|
|
2005 (100% converted to
proved developed)
|
Mississippi Canyon 296/252 (Rigel)
|
|
|
22.4
|
|
|
|
2003
|
|
|
2005 (75% converted to proved
developed/25% remains undeveloped)
|
|
|
|
(1) |
|
Net proved undeveloped reserves attributable to the project in
the year it was first added to our proved reserves. |
|
|
|
(2) |
|
This field was shut-in in April 2004 pending the drilling of a
new well and installation of an extension to the existing
infield flowline and umbilical. As a result, as of
December 31, 2005, 8.9 Bcfe of our net proved reserves
attributable to this project were classified as proved behind
pipe reserves. Production from Pluto recommenced in the third
quarter of 2006. |
The proved undeveloped reserves attributable to the remaining
two deepwater projects were added as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved
|
|
|
|
|
|
Year Expected
|
|
|
|
Undeveloped
|
|
|
|
|
|
to Convert
|
|
|
|
Reserves
|
|
|
Year
|
|
|
to Proved
|
|
Property
|
|
(Bcfe)(1)
|
|
|
Added
|
|
|
Developed Status
|
|
|
Green Canyon 646 (Daniel Boone)
|
|
|
16.4
|
|
|
|
2003
|
|
|
|
2008
|
|
Atwater Valley 380/381/382/425/426
(Bass Lite)
|
|
|
32.3
|
|
|
|
2005
|
|
|
|
2008
|
|
Ewing Bank 921 (North Black Widow)
|
|
|
3.7
|
|
|
|
2005
|
|
|
|
2006
|
|
|
|
|
(1) |
|
Net proved undeveloped reserves attributable to the project as
of December 31, 2005. |
Oil and
Natural Gas Prices and Hedging Activities
Prices for oil and natural gas can fluctuate widely, thereby
affecting the amount of cash flow available for capital
expenditures, our ability to borrow and raise additional capital
and the amount of oil and natural gas that we can economically
produce. Recently, oil and natural gas prices have been at or
near historical highs and very volatile as a result of various
factors, including weather, industrial demand, war and political
instability and uncertainty related to the ability of the energy
industry to provide supply to meet future demand.
59
Our revenues, profitability and future growth depend
substantially on prevailing prices for oil and gas and our
ability to find, develop and acquire oil and gas reserves that
are economically recoverable while controlling and reducing
costs. A substantial or extended decline in oil and natural gas
prices or poor drilling results could have a material adverse
effect on our financial position, results of operations, cash
flows, quantities of oil and natural gas reserves that we can
economically produce and access to capital.
We enter into hedging arrangements from time to time to reduce
our exposure to fluctuations in oil and natural gas prices.
Typically, our hedging strategy involves entering into commodity
price swap arrangements and costless collars with third parties.
Price swap arrangements establish a fixed price and an
index-related price for the covered commodity. When the
index-related price exceeds the fixed price, we pay the third
party the difference, and when the fixed price exceeds the
index-related prices, the third party pays us the difference.
Costless collars establish fixed cap (maximum) and floor
(minimum) prices as well as an index-related price for the
covered commodity. When the index-related price exceeds the
fixed cap price, we pay the third party the difference, and when
the index-related price is less than the fixed floor price, the
third party pays us the difference. While our hedging
arrangements enable us to achieve a more predictable cash flow,
these arrangements also limit the benefits of increased prices.
As a result of increased oil and natural gas prices, the cash
losses on contracts settled for natural gas and oil produced
during the six-month period ended June 30, 2006 was
$11.8 million. A $3.9 million non-cash gain was also
recorded for the six-month period ended June 30, 2006
relating to the hedges acquired through the Forest transaction.
Additionally, an unrealized loss of $1.0 million was
recognized for the six-month period ended June 30, 2006
related to the ineffective portion of open contracts that were
not eligible for deferral under SFAS 133 due primarily to
the basis differentials between the contract price, which is
NYMEX-based for oil and Henry Hub-based for gas, and the indexed
price at the point of sale. We incurred cash hedging losses of
$53.8 million in 2005, of which $4.5 million relates
to the hedge liability recorded at the March 2, 2004 merger
date. Major challenges related to our hedging activities include
a determination of the proper production volumes to hedge and
acceptable commodity price levels for each hedge transaction.
Our hedging activities may also require that we post cash
collateral with our counterparties from time to time to cover
credit risk. We had no collateral requirements as of
June 30, 2006, December 31, 2005 or December 31,
2004.
In accordance with purchase price accounting implemented at the
time of the merger of our former indirect parent company on
March 2, 2004, we recorded the
mark-to-market
liability of our hedge contracts at such date totaling
$12.4 million as a liability on our balance sheet.
Additionally, in accordance with purchase price accounting
implemented at the time of the Forest transaction, we recorded
the
mark-to-market
liability of Forest Energy Resources hedge contracts as of
March 2, 2006 totaling $17.5 million. As of
December 31, 2005, the amount of our
mark-to-market
hedge liabilities totaled $63.8 million and at
June 30, 2006 totaled $25.7 million. See
Liquidity and Capital Resources
Commodity Prices and Related Hedging Activities.
For the six months ended June 30, 2006, assuming a totally
unhedged position, our price sensitivity for
year-to-date
revenues for a 10% change in average oil prices and average gas
prices received is approximately $9.3 million and
$16.2 million, respectively. For the year ended
December 31, 2005, assuming a totally unhedged position,
our price sensitivity for 2005 net revenues for a 10%
change in average oil prices and average gas prices received is
approximately $9.3 million and $15.3 million,
respectively. For the year ended December 31, 2004,
assuming a totally unhedged position, our price sensitivity for
2004 historical net revenues for a 10% change in average oil
prices and average gas prices received is approximately
$8.9 million and $14.5 million, respectively.
Operating
Costs
We classify our operating costs as lease operating expense,
transportation expense, and general and administrative expenses.
Lease operating expenses are comprised of those costs and
expenses necessary to produce oil and gas after an individual
well or field has been completed and prepared for production.
These costs include direct costs such as field operations,
general maintenance expenses, work-overs, and the costs
associated with production handling agreements for most of our
deepwater fields. Lease operating expenses also include indirect
costs such as oil and gas property insurance and overhead
allocations in accordance with
60
joint operating agreements. We also include severance,
production, and ad valorem taxes as lease operating expenses.
Transportation costs are generally variable costs associated
with transportation of product to sales meters from the wellhead
or field gathering point. General and administrative include
employee compensation costs (including stock compensation
expense), the costs of third party consultants and
professionals, rent and other costs of leasing and maintaining
office space, the costs of maintaining computer hardware and
software, and insurance and other items.
Critical
Accounting Policies and Estimates
Our discussion and analysis of Mariners financial
condition and results of operations are based upon financial
statements that have been prepared in accordance with GAAP in
the U.S. The preparation of these financial statements
requires us to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses.
Our significant accounting policies are described in Note 1
to our financial statements. We analyze our estimates, including
those related to oil and gas revenues, oil and gas properties,
fair value of derivative instruments, income taxes and
contingencies and litigation, and base our estimates on
historical experience and various other assumptions that we
believe to be reasonable under the circumstances. Actual results
may differ from these estimates under different assumptions or
conditions. We believe the following critical accounting
policies affect our more significant judgments and estimates
used in the preparation of our financial statements:
Oil
and Gas Properties
Oil and gas properties are accounted for using the full-cost
method of accounting. All direct costs and certain indirect
costs associated with the acquisition, exploration and
development of oil and gas properties are capitalized.
Amortization of oil and gas properties is provided using the
unit-of-production
method based on estimated proved oil and gas reserves. No gains
or losses are recognized upon the sale or disposition of oil and
gas properties unless the sale or disposition represents a
significant quantity of oil and gas reserves, which would have a
significant impact on depreciation, depletion and amortization.
Under full cost accounting rules, total capitalized costs are
limited to a ceiling equal to the present value of future net
revenues, discounted at 10% per annum, plus the lower of cost or
fair value of unproved properties less income tax effects (the
ceiling limitation). We perform a quarterly ceiling
test to evaluate whether the net book value of our full cost
pool exceeds the ceiling limitation. If capitalized costs (net
of accumulated depreciation, depletion and amortization) less
related deferred taxes are greater than the discounted future
net revenues or ceiling limitation, a write-down or impairment
of the full cost pool is required. A write-down of the carrying
value of the full cost pool is a non-cash charge that reduces
earnings and impacts stockholders equity in the period of
occurrence and typically results in lower depreciation,
depletion and amortization expense in future periods. Once
incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices
in effect as of the balance sheet date and adjusted for
basis or location differential, held constant over
the life of the reserves. We use derivative financial
instruments that qualify for cash flow hedge accounting under
SFAS 133, Accounting for Derivative Instruments and
Hedging Activities to hedge against the volatility of
natural gas prices and, in accordance with SEC guidelines, we
include estimated future cash flows from our hedging program in
our ceiling test calculation. In addition, subsequent to the
adoption of SFAS 143, Accounting for Asset Retirement
Obligations, the future cash outflows associated with
settling asset retirement obligations are not included in the
computation of the discounted present value of future net
revenues for the purposes of the ceiling test calculation.
Proved
Reserves
Our most significant financial estimates are based on estimates
of proved natural gas and oil reserves. Estimates of proved
reserves are key components of our unevaluated properties, our
rate for recording
61
depreciation, depletion and amortization and our full cost
ceiling limitation. There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting
future revenues, rates of production and timing of development
expenditures, including many factors beyond our control. The
estimation process relies on assumptions and interpretations of
available geologic, geophysical, engineering and production
data, and the accuracy of reserve estimates is a function of the
quality and quantity of available data. Our reserves are fully
engineered on an annual basis by Ryder Scott.
Compensation
Expense
As a result of the adoption of SFAS Statement
No. 123(R), we record compensation expense for the fair
value of restricted stock and stock options that are granted. In
general, compensation expense will be determined at the date of
grant based on the fair value of the stock or options granted.
The fair value then will be amortized to compensation expense
over the applicable vesting periods.
Revenue
Recognition
We use the entitlements method of accounting for the recognition
of natural gas and oil revenues. Under this method of
accounting, income is recorded based on our net revenue interest
in production or nominated deliveries. We incur production gas
volume imbalances in the ordinary course of business. Net
deliveries in excess of entitled amounts are recorded as
liabilities, while net under deliveries are reflected as assets.
Imbalances are reduced either by subsequent recoupment of
over-and-under
deliveries or by cash settlement, as required by applicable
contracts. Production imbalances are
marked-to-market
at the end of each month at the lowest of (i) the price in
effect at the time of production; (ii) the current market
price; or (iii) the contract price, if a contract is in
hand.
Income
Taxes
Our taxable income through 2004 has been included in a
consolidated U.S. income tax return with our former
indirect parent company, Mariner Energy LLC. The intercompany
tax allocation policy provides that each member of the
consolidated group compute a provision for income taxes on a
separate return basis. We record income taxes using an asset and
liability approach which results in the recognition of deferred
tax assets and liabilities for the expected future tax
consequences of temporary differences between the book carrying
amounts and the tax bases of assets and liabilities. Valuation
allowances are established when necessary to reduce deferred tax
assets to the amount more likely than not to be recovered. In
February 2005, Mariner Energy LLC was merged into us, and we
will file our own income tax return following the effective date
of that merger. In May 2006, the State of Texas enacted
substantial changes to its tax structure beginning in 2007 by
implementing a new margin tax of 1% to be imposed on revenues
less certain costs, as specified in the legislation. During the
second quarter of 2006, we increased our provision by an
additional $1.3 million to provide for deferred taxes to
the State of Texas under the newly enacted margin tax.
Accrual
for Future Abandonment Costs
SFAS No. 143, Accounting for Asset Retirement
Obligations, addresses accounting and reporting for
obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs.
SFAS No. 143 requires that the fair value of a
liability for an assets retirement obligation be recorded
in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present
value each period, and the capitalized cost is depreciated over
the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or
loss is recognized.
Hedging
Program
In June 1998 the FASB issued SFAS No. 133,
Accounting for Derivative Instruments and Certain Hedging
Activities. In June 2000 the FASB issued
SFAS No. 138, Accounting for Certain Derivative
62
Instruments and Certain Hedging Activity, an Amendment of
SFAS No. 133. SFAS No. 133 and
SFAS No. 138 require that all derivative instruments
be recorded on the balance sheet at their respective fair values.
Mariner utilizes derivative instruments, typically in the form
of natural gas and crude oil price swap agreements and costless
collar arrangements, in order to manage price risk associated
with future crude oil and natural gas production. These
agreements are accounted for as cash flow hedges. Gains and
losses resulting from these transactions are recorded at fair
market value and deferred to the extent such amounts are
effective. Such gains or losses are recorded in Accumulated
Other Comprehensive Income (AOCI) as appropriate,
until recognized as operating income as the physical production
hedged by the contracts is delivered.
The net cash flows related to any recognized gains or losses
associated with these hedges are reported as oil and gas
revenues and presented in cash flows from operations. If the
hedge is terminated prior to expected maturity, gains or losses
are deferred and included in income in the same period as the
physical production hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify
as a cash flow hedge are the following: (i) the item to be
hedged exposes Mariner to price risk; (ii) the derivative
reduces the risk exposure and is designated as a hedge at the
time the derivative contract is entered into; and (iii) at
the inception of the hedge and throughout the hedge period there
is a high correlation of changes in the market value of the
derivative instrument and the fair value of the underlying item
being hedged.
When the designated item associated with a derivative instrument
matures, is sold, extinguished or terminated, derivative gains
or losses are recognized as part of the gain or loss on sale or
settlement of the underlying item. When a derivative instrument
is associated with an anticipated transaction that is no longer
expected to occur or if correlation no longer exists, the gain
or loss on the derivative is recognized in income to the extent
the future results have not been offset by the effects of price
or interest rate changes on the hedged item since the inception
of the hedge.
Use of
Estimates in the Preparation of Financial
Statements
The preparation of the consolidated financial statements in
conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities
at the dates of the financial statements and the reported
amounts of revenues and expenses during the reporting periods.
Our most significant financial estimates are based on remaining
proved natural gas and oil reserves. Estimates of proved
reserves are key components of our depletion rate for natural
gas and oil properties, our unevaluated properties and our full
cost ceiling test. In addition, estimates are used in computing
taxes, preparing accruals of operating costs and production
revenues, asset retirement obligations, fair value and
effectiveness of derivative instruments and fair value of stock
options and the related compensation expense. Because of the
inherent nature of the estimation process, actual results could
differ materially from these estimates.
Results
of Operations
For certain information with respect to our oil and natural gas
production, average sales price received and expenses per unit
of production, see Production.
63
Six
Months Ended June 30, 2006 Compared to Six Months Ended
June 30, 2005
Operating
and Financial Results for the Six Months Ended June 30,
2006
Compared to the Six Months Ended June 30, 2005
|
|
|
|
|
|
|
|
|
|
|
For the Six-Month Period Ended June 30,
|
|
Summary Operating Information:
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except average sales price and production
volumes)
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,524.9
|
|
|
|
988.5
|
|
Natural Gas (MMcf)
|
|
|
22,667.7
|
|
|
|
10,522.9
|
|
Total (MMcfe)
|
|
|
31,817.3
|
|
|
|
16,454.0
|
|
Average daily production (MMcfe/d)
|
|
|
175.8
|
|
|
|
90.9
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1)
|
|
$
|
57.53
|
|
|
$
|
38.88
|
|
Oil (per Bbl) unhedged
|
|
|
61.20
|
|
|
|
46.60
|
|
Natural gas (per Mcf)(1)
|
|
|
7.00
|
|
|
|
6.38
|
|
Natural gas (per Mcf) unhedged
|
|
|
7.14
|
|
|
|
6.69
|
|
Total natural gas equivalent
($/Mcfe)(1)
|
|
|
7.74
|
|
|
|
6.41
|
|
Total natural gas equivalent
($/Mcfe) unhedged
|
|
|
8.02
|
|
|
|
7.08
|
|
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
Oil sales(1)
|
|
$
|
87,726
|
|
|
$
|
38,435
|
|
Gas sales(1)
|
|
|
158,576
|
|
|
|
67,090
|
|
Total oil and gas revenues(1)
|
|
|
246,302
|
|
|
|
105,525
|
|
Other revenues
|
|
|
1,623
|
|
|
|
2,058
|
|
Lease operating expenses
|
|
|
37,567
|
|
|
|
13,194
|
|
Transportation expenses
|
|
|
2,277
|
|
|
|
1,501
|
|
Depreciation, depletion and
amortization
|
|
|
109,806
|
|
|
|
31,054
|
|
General and administrative expenses
|
|
|
17,473
|
|
|
|
15,400
|
|
Net interest expense
|
|
|
14,419
|
|
|
|
3,006
|
|
Income before taxes
|
|
|
66,383
|
|
|
|
43,428
|
|
Provision for income taxes
|
|
|
24,549
|
|
|
|
14,808
|
|
Net Income
|
|
|
41,834
|
|
|
|
28,620
|
|
|
|
|
(1) |
|
Includes the effects of hedging |
Production: Production for the first six
months of 2006 averaged 176 MMcfe per day (31.8 Bcfe
total for the period) compared to average daily production of
91 MMcfe per day for the first six months of 2005
(16.5 Bcfe total for the period). The increased production
levels for the six months ended June 30, 2006 resulted
primarily from the acquisition of the Forest Gulf of Mexico
operations. The first six months of 2006 continued to be
adversely effected by the 2005 hurricane season, resulting in
shut-in production and startup delays. We estimate that as of
September 30, 2006, approximately 12 MMcfe per day of
production remained shut-in and approximately 33 MMcfe per
day of production had recommenced since June 30, 2006. The
four deepwater projects that experienced startup delays have
recommenced production. As a result of ongoing repairs to
pipelines, facilities, terminals and host facilities, we expect
most of the remaining shut-in production to recommence by the
end of 2006 and the balance in 2007, except that an immaterial
amount of production is not expected to recommence.
64
Production in the Gulf of Mexico increased 102%, to
27.4 Bcfe from 13.5 Bcfe for the six-month periods ended
June 30, 2006 and 2005, respectively, while onshore
production increased 53%, to 4.5 Bcfe from 2.9 Bcfe
for the six-month periods ended June 30, 2006 and 2005,
respectively. Natural gas production comprised 71% of our total
production for the first six months of 2006, respectively,
compared to 64% for the comparable period of 2005. The increase
in the
gas-to-oil
ratio was primarily the result of the acquisition of the Forest
Gulf of Mexico operations.
Oil and gas revenues: Total oil and gas
revenues increased 133%, to $246.3 million for the
six-month period ended June 30, 2006 compared to
$105.5 million for the six-month period ended June 30,
2005. Natural gas revenues were $158.6 million compared to
$67.1 million for the six-month period ended June 30,
2005. Total oil revenues for the six-month period ended
June 30, 2006 were $87.7 million, compared to
$38.4 million for the six-month period ended June 30,
2005.
Natural gas prices (excluding the effects of hedging) for the
first six months of 2006 averaged $7.14/Mcf compared to
$6.69/Mcf for the comparable period of 2005. Oil prices
(excluding the effects of hedging) for the first six months of
2006 averaged $61.20/Bbl compared to $46.60/Bbl for the
comparable period of 2005. For the first six months of 2006,
hedges decreased average natural gas pricing by $0.14/Mcf to
$7.00/Mcf and reduced average oil pricing by $3.67/Bbl to
$57.53/Bbl, resulting in a net recognized hedging loss of
$8.9 million.
The cash losses on contracts settled for natural gas and oil
produced during the six-month period ended June 30, 2006
was $11.8 million. A $3.9 million non-cash gain was
also recorded for the six-month period ended June 30, 2006
relating to the hedges acquired through the Forest Energy
Resources merger. Additionally, an unrealized loss of
$1.0 million was recognized for the six-month period ended
June 30, 2006 related to the ineffective portion of open
contracts that were not eligible for deferral under
SFAS 133 due primarily to the basis differentials between
the contract price, which is NYMEX-based for oil and Henry
Hub-based for gas, and the indexed price at the point of sale.
Lease operating expenses (including severance, ad valorem
taxes and workover expenses) were $37.6 million for the
six-month period ended June 30, 2006 compared to
$13.2 million for the six-month period ended June 30,
2005. The increase primarily was attributable to the
consolidation of the Forest Gulf of Mexico operations and
increased costs attributable to the addition of new productive
wells onshore. Lease operating expenses rose to $1.18 for the
six-month period ended June 30, 2006 compared to
$0.80 per Mcfe for the six-month period ended June 30,
2005. Continued shut-in production from the impact of the 2005
hurricanes contributed to the increased per-unit operating costs.
Transportation expenses were $2.3 million for the
six-month period ended June 30, 2006, or $0.07 per
Mcfe, compared to $1.5 million, or $0.09 per Mcfe, for
the six-month period ended June 30, 2005. The increase is
primarily a result of the consolidation of the Forest Gulf of
Mexico operations.
Depreciation, depletion, and amortization
(DD&A) expense increased 254% to
$109.8 million from $31.1 million for the six-month
periods ended June 30, 2006 and 2005, respectively. The
increase was a result of increased production due to the
consolidation of the Forest Gulf of Mexico operations, as well
as an increase in the
unit-of-production
depreciation, depletion and amortization rate to $3.45 per
Mcfe from $1.89 per Mcfe for the six-month periods ended
June 30, 2006 and 2005, respectively. The per unit increase
was primarily the result of consolidation of the Forest Gulf of
Mexico operations at their estimated fair value as of the
transaction date and the accretion of asset retirement
obligations.
General and administrative (G&A) expenses
totaled $17.5 million for the first six months of 2006
compared to $15.4 million in the first six months of 2005.
For the first six months of 2006, G&A expense includes
charges for stock compensation expense of $7.9 million
compared to $9.5 million in the first six months of 2005.
For the first six months of 2006, $6.6 million resulted
from amortization of the cost of restricted stock granted at the
closing of Mariners private equity placement in March
2005. The restricted stock has fully vested and there will be no
future charges related to those stock grants. New restricted
stock grants were made in the second quarter 2006 with vesting
periods of three to four years. Included in the G&A increase
are severance, retention, relocation and transition costs
related to the Forest Energy Resources merger
65
of approximately $2.5 million for the first six months of
2006. Salaries and wages in the first six months of 2006
increased by $7.2 million compared to year earlier periods.
The increase was primarily the result of staffing additions
related to the Forest Energy Resources merger. In addition, the
first half of 2005 included $2.3 million in payments to our
former stockholders to terminate a services agreement. Reported
G&A expenses in the first six months of 2006 are net of
$7.8 million of overhead reimbursements billed or received
from other working interest owners, compared to
$2.4 million for the comparable period of 2005.
Net interest expense increased 380% to $14.4 million
from $3.0 million for the six-month period ended
June 30, 2006 and 2005, respectively. This increase was
primarily due to an increase in average debt levels to
$346.7 million compared to $88.8 million for the
six-month periods ended June 30, 2006 and 2005,
respectively. The increased debt was primarily the result of the
debt assumed in the Forest Energy Resources merger and the use
of our secured credit facility to finance capital expenditures
in excess of cash flows. Additionally, the amendment and
restatement of the credit facility on March 2, 2006 was
treated as an extinguishment of debt for accounting purposes,
and resulted in a charge of $1.2 million of related debt
issuance costs.
Income before income taxes increased to
$66.4 million and $43.4 million for the six-month
periods ended June 30, 2006 and 2005, respectively. This
increase was primarily the result of higher operating income
attributed to the Forest Gulf of Mexico operations.
Provision for income taxes had an effective tax rate of
37.0% for the six month period ended June 30, 2006 as
compared to an effective tax rate of 34.1% for the comparable
period of 2005. The increase in the effective tax rate is
primarily a result of the Texas Margins tax, which was enacted
during the second quarter of 2006 for all properties residing in
Texas. Excluding the effects of the Texas Margins tax, the
effective rate would have been 35% for the six months ended
June 30, 2006.
Year
Ended December 31, 2005 compared to Year Ended
December 31, 2004
Operating
and Financial Results for the Year Ended December 31,
2005
Compared to the Year Ended December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Non-GAAP
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Combined
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
Year Ended
|
|
|
2004 through
|
|
|
2004 through
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
Summary Operating Information:
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands, except average sales price)
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,791
|
|
|
|
2,298
|
|
|
|
1,885
|
|
|
|
413
|
|
Natural gas (MMcf)
|
|
|
18,354
|
|
|
|
23,782
|
|
|
|
19,549
|
|
|
|
4,233
|
|
Total (MMcfe)
|
|
|
29,100
|
|
|
|
37,569
|
|
|
|
30,856
|
|
|
|
6,713
|
|
Average daily production (MMcfe/d)
|
|
|
80
|
|
|
|
103
|
|
|
|
101
|
|
|
|
112
|
|
Hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues (loss)
|
|
$
|
(18,671
|
)
|
|
$
|
(12,300
|
)
|
|
$
|
(11,614
|
)
|
|
$
|
(686
|
)
|
Gas revenues (loss)
|
|
|
(30,613
|
)
|
|
|
(7,498
|
)
|
|
|
(8,929
|
)
|
|
|
1,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenues (loss)
|
|
$
|
(49,284
|
)
|
|
$
|
(19,798
|
)
|
|
$
|
(20,543
|
)
|
|
$
|
745
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) realized(1)
|
|
$
|
41.23
|
|
|
$
|
33.17
|
|
|
$
|
33.69
|
|
|
$
|
30.75
|
|
Oil (per Bbl) unhedged
|
|
|
51.66
|
|
|
|
38.52
|
|
|
|
39.86
|
|
|
|
32.41
|
|
Natural gas (per Mcf) realized(1)
|
|
|
6.66
|
|
|
|
5.80
|
|
|
|
5.67
|
|
|
|
6.39
|
|
Natural gas (per Mcf) unhedged
|
|
|
8.33
|
|
|
|
6.12
|
|
|
|
6.13
|
|
|
|
6.05
|
|
Total natural gas equivalent
($/Mcfe) realized(1)
|
|
|
6.74
|
|
|
|
5.70
|
|
|
|
5.65
|
|
|
|
5.92
|
|
Total natural gas equivalent
($/Mcfe) unhedged
|
|
|
8.43
|
|
|
|
6.23
|
|
|
|
6.32
|
|
|
|
5.81
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Non-GAAP
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Combined
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
Year Ended
|
|
|
2004 through
|
|
|
2004 through
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
Summary Operating Information:
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands, except average sales price)
|
|
|
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
73,831
|
|
|
$
|
76,207
|
|
|
$
|
63,498
|
|
|
$
|
12,709
|
|
Gas sales
|
|
|
122,291
|
|
|
|
137,980
|
|
|
|
110,925
|
|
|
|
27,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenues
|
|
$
|
196,122
|
|
|
$
|
214,187
|
|
|
$
|
174,423
|
|
|
$
|
39,764
|
|
Other revenues
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
29,882
|
|
|
|
25,484
|
|
|
|
21,363
|
|
|
|
4,121
|
|
Transportation expenses
|
|
|
2,336
|
|
|
|
3,029
|
|
|
|
1,959
|
|
|
|
1,070
|
|
Depreciation, depletion and
amortization
|
|
|
59,426
|
|
|
|
64,911
|
|
|
|
54,281
|
|
|
|
10,630
|
|
General and administrative expenses
|
|
|
37,053
|
|
|
|
8,772
|
|
|
|
7,641
|
|
|
|
1,131
|
|
Impairment of production equipment
held for use
|
|
|
1,845
|
|
|
|
957
|
|
|
|
957
|
|
|
|
|
|
Net interest expense (income)
|
|
|
7,393
|
|
|
|
5,734
|
|
|
|
5,820
|
|
|
|
(86
|
)
|
Income before taxes
|
|
|
61,775
|
|
|
|
105,300
|
|
|
|
82,402
|
|
|
|
22,898
|
|
Provision for income taxes
|
|
|
21,294
|
|
|
|
36,855
|
|
|
|
28,783
|
|
|
|
8,072
|
|
Net income
|
|
|
40,481
|
|
|
|
68,445
|
|
|
|
53,619
|
|
|
|
14,826
|
|
|
|
|
(1) |
|
Average realized prices include the effects of hedges. |
Net production during 2005 decreased approximately 23% to
29.1 Bcfe from 37.6 Bcfe in 2004 primarily due to
decreased Gulf of Mexico production, partially offset by
increased onshore production. Mariners production was
negatively impacted during the third and fourth quarters of 2005
due to hurricane activity, primarily Katrina and Rita.
Production shut-in and deferred because of the hurricanes
impact totaled approximately 6-8 Bcfe during the third and
fourth quarters of 2005. As of December 31, 2005,
approximately 5 MMcfe per day of production remained
shut-in awaiting repairs, primarily associated with our Baccarat
property (although, production therefrom recommenced in January
2006). Additionally, production that was anticipated to commence
in 2005 at our Swordfish, Ochre, Pluto, and Rigel development
projects was delayed awaiting repairs to host facilities.
Swordfish recommenced production in the fourth quarter of 2005,
Rigel recommenced production in the first quarter of 2006, and
Ochre and Pluto recommenced production in the third quarter of
2006.
Increased development drilling at our Aldwell unit in West Texas
contributed to a 60% increase in onshore production to an
average of approximately 18.1 MMcfe per day in 2005 from an
average of approximately 11.3 MMcfe per day in 2004.
In the deepwater Gulf of Mexico, production decreased
approximately 32% to an average of approximately 32.3 MMcfe
per day in 2005 compared to an average of approximately
47.2 MMcfe per day in 2004. The decrease was largely due to
reduced production at our Black Widow, Yosemite and Pluto
fields. Pluto was shut-in in April 2004 pending drilling of the
new Mississippi Canyon 674 #3 well and installation of
an extension to the existing subsea facilities. Production at
Black Widow and Yosemite was negatively impacted by hurricane
activity as well as by expected declines. As previously
discussed, hurricane-related delays in commencement of
production at our Swordfish, Pluto and Rigel development
projects also contributed to the production decline.
In the Gulf of Mexico shelf, production decreased by
approximately 34% to an average of approximately 29.2 MMcfe
per day in 2005 from an average of approximately 44.1 MMcfe
per day in 2004. About 6.2 MMcfe per day of the decrease is
attributable to our Ochre field, which remains shut-in due to
the effects of Hurricane Ivan in September 2004 and Hurricanes
Katrina and Rita in 2005. Production from three new shelf
discoveries (Green Pepper, Royal Flush, and Dice) and production
from the 2004 acquisition of interests
67
in five offshore fields offset normal declines at our other Gulf
of Mexico shelf fields and the impact of the 2005 hurricane
season.
Hedging activities in 2005 decreased our average realized
natural gas price received by $1.67 per Mcf and revenues by
$30.6 million, compared with a decrease of $0.32 per
Mcf and revenues of $7.5 million in 2004. Our hedging
activities with respect to crude oil during 2005 decreased the
average sales price received by $10.43 per barrel and
revenues by $18.7 million compared with a decrease of
$5.35 per barrel and revenues of $12.3 million for
2004.
Oil and gas revenues decreased 8% to $196.1 million
in 2005 when compared to 2004 oil and gas revenues of
$214.2 million, due to the aforementioned 23% decrease in
production, partially offset by an 18% increase in realized
prices (including the effects of hedging) to $6.74 per Mcfe
in 2005 from $5.70 per Mcfe in 2004.
Other revenues of $3.6 million in 2005 represent an
indemnity payment of $1.9 million received from our former
stockholder related to the 2004 merger and $1.7 million
generated by our West Texas Aldwell unit gathering system.
Lease operating expenses increased 17% to
$29.9 million in 2005 from $25.5 million in 2004. The
increased costs were primarily attributable to the addition of
new producing wells at our Aldwell Unit offset by reduced costs
on our Black Widow, King Kong/Yosemite, and Pluto deepwater
fields. On a per unit basis, lease operating expenses were
$1.03 per Mcfe in 2005 compared to $0.68 per Mcfe in 2004.
The increased per unit costs also reflect lower production rates
in 2005, including hurricane-related disruptions.
Transportation expenses were $2.3 million or
$0.08 per Mcfe in 2005, compared to $3.0 million or
$0.08 per Mcfe in 2004. The reduction is primarily
attributable to our deepwater fields and includes reductions
caused by the filing of new and higher transportation allowances
with the MMS on two of our deepwater fields for purpose of
royalty calculation.
Depreciation, depletion, and amortization
(DD&A) expense decreased 8% to
$59.4 million during 2005 from $64.9 million for 2004
as a result of decreased production of 8.5 Bcfe in 2005
compared to 2004, partially offset by an increase in the
unit-of-production
depreciation, depletion and amortization rate to $2.04 per
Mcfe for 2005 from $1.73 per Mcfe for 2004. The per unit
increase was primarily the result of an increase in future
development costs on our deepwater development fields.
General and administrative (G&A) expenses,
which are net of $6.9 million and $4.4 million of
overhead reimbursements billed or received from other working
interest owners in 2005 and 2004, respectively, increased 322%
to $37.1 million during 2005 compared to $8.8 million
in 2004. The increase was primarily due to recognizing
$25.7 million in stock compensation expense related to
restricted stock and options granted in 2005. We also paid
$2.3 million to our former stockholders to terminate a
services agreement in 2005, compared to $1.0 million under
the same agreement in 2004. In addition, G&A expenses
increased by $1.6 million due to a reduction in the amount
of G&A capitalized in 2005 compared to 2004.
Impairment of production equipment held for use reflects
the reduction of the carrying cost of our inventory by
$1.8 million and $1.0 million as of December 31,
2005 and December 31, 2004, respectively. In 2005, the
reduction in estimated value primarily related to subsea trees
and wellhead equipment held in inventory.
Net interest expense for 2005 increased 25% to
$7.4 million from $5.7 million in 2004, primarily due
to higher average debt levels in 2005 compared to 2004. In
connection with the merger on March 2, 2004, Mariner
incurred $135 million in new bank debt and issued a
$10 million promissory note to JEDI. For comparison
purposes, approximately ten months of interest related to such
borrowings is reflected in 2004 compared to twelve months of
interest in 2005.
Income before income taxes decreased to
$61.8 million for 2005 compared to $105.3 million for
2004, attributable primarily to the decrease in oil and gas
revenues resulting from the decreased production and increased
G&A expenses, both as noted above. Offsetting these factors
were the receipt of other income related to the indemnity
payment and lower DD&A and transportation expenses.
68
Provision for income taxes decreased to
$21.3 million for 2005 from $36.9 million for 2004 as
a result of decreased operating income for 2005 compared to 2004.
Year
Ended December 31, 2004 compared to Year Ended
December 31, 2003
Operating
and Financial Results for the Year Ended December 31,
2004
Compared to the Year Ended December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Non-GAAP
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
Combined
|
|
|
2004 through
|
|
|
2004 through
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
Summary Operating Information:
|
|
2003
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands, except average sales price)
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,600
|
|
|
|
2,298
|
|
|
|
1,885
|
|
|
|
413
|
|
Natural gas (MMcf)
|
|
|
23,772
|
|
|
|
23,782
|
|
|
|
19,549
|
|
|
|
4,233
|
|
Total (MMcfe)
|
|
|
33,374
|
|
|
|
37,569
|
|
|
|
30,856
|
|
|
|
6,713
|
|
Average daily production (MMcfe/d)
|
|
|
91
|
|
|
|
103
|
|
|
|
101
|
|
|
|
112
|
|
Hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues (loss)
|
|
$
|
(4,969
|
)
|
|
$
|
(12,299
|
)
|
|
$
|
(11,613
|
)
|
|
$
|
(686
|
)
|
Gas revenues (loss)
|
|
|
(24,494
|
)
|
|
|
(7,498
|
)
|
|
|
(8,929
|
)
|
|
|
1,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenues (loss)
|
|
$
|
(29,463
|
)
|
|
$
|
(19,797
|
)
|
|
$
|
(20,542
|
)
|
|
$
|
745
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) realized(1)
|
|
$
|
23.74
|
|
|
$
|
33.17
|
|
|
$
|
33.69
|
|
|
$
|
30.75
|
|
Oil (per Bbl) unhedged
|
|
|
26.85
|
|
|
|
38.52
|
|
|
|
39.85
|
|
|
|
32.41
|
|
Natural gas (per Mcf) realized(1)
|
|
|
4.40
|
|
|
|
5.80
|
|
|
|
5.67
|
|
|
|
6.39
|
|
Natural gas (per Mcf) unhedged
|
|
|
5.43
|
|
|
|
6.12
|
|
|
|
6.13
|
|
|
|
6.05
|
|
Total natural gas equivalent
($/Mcfe) realized(1)
|
|
|
4.27
|
|
|
|
5.70
|
|
|
|
5.65
|
|
|
|
5.92
|
|
Total natural gas equivalent
($/Mcfe) unhedged
|
|
|
5.15
|
|
|
|
6.23
|
|
|
|
6.32
|
|
|
|
5.81
|
|
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
37,992
|
|
|
$
|
76,207
|
|
|
$
|
63,498
|
|
|
$
|
12,709
|
|
Gas sales
|
|
|
104,551
|
|
|
|
137,980
|
|
|
|
110,925
|
|
|
|
27,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenue
|
|
$
|
142,543
|
|
|
$
|
214,187
|
|
|
$
|
174,423
|
|
|
$
|
39,764
|
|
Lease operating expenses
|
|
|
24,719
|
|
|
|
25,484
|
|
|
|
21,363
|
|
|
|
4,121
|
|
Transportation expenses
|
|
|
6,252
|
|
|
|
3,029
|
|
|
|
1,959
|
|
|
|
1,070
|
|
Depreciation, depletion and
amortization
|
|
|
48,339
|
|
|
|
64,911
|
|
|
|
54,281
|
|
|
|
10,630
|
|
General and administrative expenses
|
|
|
8,098
|
|
|
|
8,772
|
|
|
|
7,641
|
|
|
|
1,131
|
|
Impairment of production equipment
held for use
|
|
|
|
|
|
|
957
|
|
|
|
957
|
|
|
|
|
|
Net interest expense (income)
|
|
|
6,225
|
|
|
|
5,734
|
|
|
|
5,820
|
|
|
|
(86
|
)
|
Income before taxes and change in
accounting method
|
|
|
45,688
|
|
|
|
105,300
|
|
|
|
82,402
|
|
|
|
22,898
|
|
Provision for income taxes
|
|
|
9,387
|
|
|
|
36,855
|
|
|
|
28,783
|
|
|
|
8,072
|
|
Net income
|
|
|
38,244
|
|
|
|
68,445
|
|
|
|
53,619
|
|
|
|
14,826
|
|
|
|
|
(1) |
|
Average realized prices include the effects of hedges. |
69
Net production during 2004 increased to 37.6 Bcfe
from 33.4 Bcfe during 2003 primarily due to the
commencement of production on our Roaring Fork and Ochre
projects, offset by normal production declines on existing
fields.
Hedging activities in 2004 decreased our average realized
natural gas price received by $0.32 per Mcf and revenues by
$7.5 million, compared with a decrease of $1.03 per
Mcf and revenues of $24.5 million for 2003. Our hedging
activities with respect to crude oil during 2004 decreased the
average sales price received by $5.35 per bbl and revenues
by $12.3 million compared with a decrease of $3.11 per
bbl and revenues of $5.0 million for 2003.
Oil and gas revenues increased 50% to $214.2 million
during 2004 when compared to 2003 oil and gas revenues of
$142.5 million, due to a 13% increase in production and a
33% increase in realized prices (including the effects of
hedging) to $5.70 per Mcfe in 2004 from $4.27 per Mcfe
in 2003.
Lease operating expenses increased 3% to
$25.5 million in 2004 from $24.7 million in 2003 due
to increased activity in our West Texas Aldwell project,
partially offset by lower compression costs on our King Kong and
Yosemite projects and the shut-in of our Pluto project for a
large portion of 2004 pending the drilling and completion of the
Mississippi Canyon 674 No. 3 well, which has been drilled
and awaits installation of flowlines and related facilities.
Transportation expenses were $3.0 million for 2004,
compared to $6.3 million for 2003. In the fourth quarter of
2004, we filed new transportation allowances with the MMS for
purpose of royalty calculation. This resulted in a
$3.2 million decrease in transportation expense in 2004
compared to 2003. In addition, transportation expense from our
new Roaring Fork field was offset by declines from our existing
fields.
DD&A expense increased 34% to $64.9 million
during 2004 from $48.3 million for 2003 as a result of an
increase in the
unit-of-production
depreciation, depletion and amortization rate to $1.73 per
Mcfe from $1.45 per Mcfe for the comparable period and a
production increase of 4.2 Bcfe in 2004 compared to 2003.
The per unit increase is primarily attributable to non-cash
purchase accounting adjustments resulting from the merger.
G&A expenses, which are net of $4.4 million of
overhead reimbursements received from other working interest
owners, increased 8% to $8.8 million during 2004 compared
to $8.1 million in 2003 primarily due to increased
compensation costs paid in connection with the merger and
payments made pursuant to services contracts with affiliates of
our sole stockholder, offset by increased overhead recoveries
from our partners and amounts capitalized.
Impairment of production equipment held for use reflects
the reduction of the carrying cost of our inventory as of
December 31, 2004 by $1.0 million to account for a
reduction in estimated value primarily related to subsea trees
held in inventory.
Net interest expense for 2004 decreased 8% to
$5.7 million from $6.2 million for 2003, primarily due
to the repayment of our senior subordinated notes in August
2003, replaced by lower-cost bank debt in March 2004.
Income before income taxes and change in accounting method
increased to $105.3 million for 2004 compared to
$45.7 million in 2003, attributable primarily to the
increase in oil and gas revenues resulting from the increased
production and realized prices noted above.
Provision for income taxes increased to
$36.9 million for 2004 from $9.4 million for 2003 as a
result of increased current year operating income.
Liquidity
and Capital Resources
Cash
Flows and Liquidity
Secured Bank Credit Facility. At
December 31, 2005, we had $152 million in advances
outstanding under our secured revolving credit facility with a
borrowing base as of that date of $170 million. In January
2006, the borrowing base was increased to $185 million. In
connection with the merger with Forest Energy
70
Resources on March 2, 2006, we amended and restated our
existing credit facility to increase maximum credit availability
to $500 million for revolving loans, including up to
$50 million in letters of credit, with a $400 million
borrowing base as of that date. On March 2, 2006, after
giving effect to funds required at closing to refinance
$176.2 million of debt assumed in the merger and other
merger-related costs, our total debt drawn under the facility
was approximately $350 million, including a
$4.2 million letter of credit required for plugging and
abandonment obligations at one of our offshore fields. On
April 7, 2006, the borrowing base under the secured credit
facility was increased to $430 million, subject to
redetermination or adjustment. On April 24, 2006, the
borrowing base was reduced to $362.5 million in accordance
with an amendment to the credit facility related to our offering
of $300 million of senior notes. For subsequent qualifying
bond issuances, the amendment provides that the borrowing base
in effect on the closing date of such a bond issuance will
automatically reduce by 25% of the aggregate principal amount of
such bond issuance to the extent that it does not refinance the
principal amount of an existing bond issuance. The secured
credit facility permits Mariners issuance of certain
unsecured bonds of up to $350 million in aggregate
principal amount that have a non-default interest rate of 10% or
less per annum and a scheduled maturity date after March 1,
2012. Mariners sale and issuance of $300 million of
senior notes in April 2006 constituted such a qualifying bond
issuance. At June 30, 2006, approximately
$161.2 million was outstanding under our revolving secured
credit facility, including the $4.2 million letter of
credit. We anticipate that the borrowing base will be increased
to $450 million in October 2006, subject to redetermination
or adjustment. This credit facility matures on March 2,
2010.
The amendment and restatement of our secured credit facility on
March 2, 2006 also provided for an additional
$40 million letter of credit for the benefit of Forest to
guarantee certain drilling obligations in West Texas. This
letter of credit is not included as a use of our borrowing base
availability and matures on March 2, 2009. The amount of
the letter of credit is to reduce periodically, with the
reduction amount depending upon the number of wells drilled.
Based upon the number of wells drilled as of September 30,
2006, the first reduction is expected in October 2006.
Private Placement of Senior Unsecured Notes due
2013. On April 24, 2006, Mariner sold and
issued to eligible purchasers $300 million aggregate
principal amount of its
71/2% senior
notes due 2013 pursuant to Rule 144A under the Securities
Act. The notes were priced to yield 7.75% to maturity. Net
proceeds, after deducting initial purchasers discounts and
commissions and offering expenses, were approximately
$287.9 million. Mariner used the net proceeds to repay
borrowings under its secured credit facility. The issuance of
the notes was a qualifying bond issuance under Mariners
secured credit facility and resulted in an automatic reduction
of its borrowing base to $362.5 million as of
April 24, 2006. For a description of the terms of the
notes, see Description of Senior Notes. Costs
associated with the notes offering were approximately
$8.3 million, excluding discounts of $3.8 million.
JEDI Term Promissory Note. As part of the 2004
merger consideration payable to JEDI, we issued a term
promissory note to JEDI in the amount of $10 million. The
note bore interest, payable in kind at our option, at a rate of
10% per annum until March 2, 2005, and 12% per
annum thereafter unless paid in cash in which event the rate
remained 10% per annum. We chose to pay the interest in
cash rather than in kind. The JEDI note was secured by a lien on
three of our Gulf of Mexico properties with no proved reserves.
We could offset against the note the amount of certain claims
for indemnification that could be asserted against JEDI under
the terms of the merger agreement. The JEDI note contained
customary events of default, including an event of default
triggered by the occurrence of an event of default under our
credit facility. We used $6 million of the proceeds from
the 2005 private equity placement to repay a portion of the JEDI
note. As of December 31, 2005, $4 million was still
outstanding under the JEDI note. This note was repaid in full on
its maturity date of March 2, 2006.
Working Capital. Working capital at
June 30, 2006 was a negative $100.8 million, excluding
current derivative liabilities and deferred taxes. This was a
result of increased accrued capital obligations for drilling and
development projects in progress. Working capital at
December 31, 2005 was negative $46.4 million,
excluding current derivative liabilities and deferred taxes.
Accrued liabilities (including accounts payable) and accrued
receivables (including accounts receivable) at December 31,
2005 increased by approximately 91% and 68%, respectively, over
levels at December 31, 2004 primarily due to increased
accrued obligations for
71
drilling and development projects in progress at year end 2005
and related accruals of amounts owed by partners. As of
December 31, 2004, we had negative working capital of
approximately $18.7 million compared to positive working
capital of $38.3 million at December 31, 2003, in each
case excluding current derivative liabilities and restricted
cash. The reduction in working capital from 2003 is primarily
the result of a change in the manner Mariner utilizes excess
cash. At year end 2003, Mariner operated with no debt and
consequently accumulated cash (approximately $60 million at
year end 2003) generated by operations and asset sales in
order to fund future obligations and business activities. In
March 2004, Mariner entered into a revolving credit facility,
and since then has utilized excess cash to pay down outstanding
advances to maintain debt levels as low as possible. In
addition, our accounts payable and accrued liabilities at
December 31, 2004 increased by about 32% over levels at
December 31, 2003 primarily as a result of funding for
development of our deepwater projects in progress at year end.
Capital Expenditures. In the first six months
of 2006, our capital expenditures were $272.9 million, of
which 46% related to development activities, 51% related to
exploration activities, including the acquisition of leasehold
and seismic, and the balance related to capitalized expenses and
minor corporate items. Our 2005 capital expenditures were
$252.7 million. Approximately 48% of our capital
expenditures were incurred for development projects, 24% for
exploration activities, 21% for acquisitions of developed
properties, and the remainder for other items (primarily
expenditures for our Aldwell gathering system, capitalized
overhead and interest). The following table presents major
components of our capital expenditures for the six months ended
June 30, 2006 and for each of the three years in the period
ended December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
Combined
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
Year
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
2004 to
|
|
|
2004 to
|
|
|
Year Ended
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
(In millions)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition
|
|
$
|
16.5
|
|
|
$
|
11.5
|
|
|
$
|
4.8
|
|
|
$
|
4.4
|
|
|
$
|
0.4
|
|
|
$
|
4.8
|
|
Oil and natural gas exploration
|
|
|
122.2
|
|
|
|
50.0
|
|
|
|
43.0
|
|
|
|
35.9
|
|
|
|
7.1
|
|
|
|
26.8
|
|
Oil and natural gas development
|
|
|
126.1
|
|
|
|
121.7
|
|
|
|
88.6
|
|
|
|
82.0
|
|
|
|
6.6
|
|
|
|
44.3
|
|
Proceeds from property conveyances
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6
|
)
|
Acquisitions
|
|
|
|
|
|
|
53.4
|
|
|
|
4.9
|
|
|
|
4.9
|
|
|
|
|
|
|
|
|
|
Other items (primarily gathering
system, capitalized overhead and interest)
|
|
|
8.1
|
|
|
|
16.1
|
|
|
|
7.6
|
|
|
|
6.4
|
|
|
|
1.2
|
|
|
|
7.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures, net of
proceeds from property conveyances
|
|
$
|
270.9
|
|
|
$
|
252.7
|
|
|
$
|
148.9
|
|
|
$
|
133.6
|
|
|
$
|
15.3
|
|
|
$
|
(38.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our net capital expenditures for 2005 increased by
$103.8 million as compared to 2004, primarily as a result
of increased acquisitions, primarily in West Texas, and
increased expenditures on development activities. Our net
capital expenditures for 2004 increased by $187.2 million,
as compared to 2003, as a result of increased exploration and
development expenditures with no offsetting proceeds from
property conveyances in 2004.
We had no long-term debt outstanding as of December 31,
2003. As of December 31, 2005 and 2004, long-term debt was
$156 million and $115 million, respectively. As of
June 30, 2006, long-term debt was $457 million.
We anticipate that total capital expenditures for 2006 will
approximate $463.5 million (of which approximately
$70.9 million is attributable to the West Cameron
acquisition described under Recent
Developments), with approximately 57% allocated to
development activities, 41% to exploration activities, and the
remainder to other items (primarily capitalized overhead and
interest). The 2006 budget is an increase
72
of approximately 83% over our 2005 expenditures. The increase is
primarily driven by the addition of the Forest Gulf of Mexico
operations, continuation of our deepwater development
activities, and expansion of our exploration activities,
including increasing our acquisition of leasehold and seismic
data. In addition, we expect to incur approximately
$80 million for repairs of damage caused by Hurricanes
Katrina and Rita. While this will be a cash outflow in 2006, we
expect to recover these costs through insurance reimbursements
later in 2006 or 2007. Since we believe these costs to be
reimbursable, they will not be reflected in reported 2006
capital expenditures.
Cash Flows. During the second quarter of 2006,
we utilized our secured credit facility to fund amounts due
pursuant to the Forest Energy Resources merger and for capital
expenditures incurred in excess of cash flows. Although we
expect to fund exploration and development capital expenditures
in the second half of 2006 from internally generated cash flows,
the credit facility may be utilized for such expenditures
exceeding current projections and for acquisitions.
The timing of expenditures (especially regarding deepwater
projects) is unpredictable. Also, our cash flows are heavily
dependent on the oil and natural gas commodity markets, and our
ability to hedge oil and natural gas prices is limited by our
revolving credit facility to no more than 80% of our expected
production from proved developed producing reserves. If either
oil or natural gas commodity prices decrease from their current
levels, our ability to finance our planned capital expenditures
could be affected negatively. Amounts available for borrowing
under our revolving credit facility are largely dependent on our
level of proved reserves and current oil and natural gas prices.
If either our proved reserves or commodity prices decrease,
amounts available to us to borrow under our revolving credit
facility could be reduced. If our cash flows are less than
anticipated or amounts available for borrowing under our
revolving credit facility are reduced or we can not access the
high yield or other debt markets, we may be forced to defer
planned capital expenditures.
In addition, our future oil and natural gas production depends
on our success in finding or acquiring additional reserves. If
we fail to replace reserves through drilling or acquisitions,
our cash flows will be affected adversely. In general,
production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on
reservoir characteristics. Our total proved reserves decline as
reserves are produced unless we conduct other successful
exploration and development activities or acquire properties
containing proved reserves, or both. Our ability to make the
necessary capital investment to maintain or expand our asset
base of oil and natural gas reserves would be impaired to the
extent cash flow from operations is reduced and external sources
of capital become limited or unavailable. We may not be
successful in exploring for, developing or acquiring additional
reserves.
Our existing proved reserves are comprised of West Texas and
Gulf of Mexico properties. The West Texas properties are
relatively long-life in nature characterized by relatively low
decline rates (lower productive rates) while the Gulf of Mexico
properties are shorter-life in nature characterized by
relatively high decline rates (higher productive rates). For the
year ended December 31, 2005, our Gulf of Mexico properties
comprised about 77% of our total production or 93% on a pro
forma basis. We plan to maintain an active drilling program for
our onshore properties with the intention of maintaining or
increasing production in those areas. Although production from
our existing offshore wells will decline more rapidly over time
than our onshore wells, the percentage of production
attributable to our offshore wells is expected to increase in
the coming years as more of our undeveloped deep water projects
commence production and we begin to exploit our newly acquired
offshore assets. While we expect this trend to continue for the
near future, oil and gas production (especially for our offshore
properties) can be heavily affected by reservoir characteristics
and unforeseen events (such as hurricanes and other casualties),
so we can not predict with any certainty the timing of declines
in production or the commencement of production from new
projects.
In conjunction with the March 2004 merger, we established a new
credit facility maturing on March 2, 2007 that subsequently
was amended and restated. The new credit facility was fully
drawn at inception for $135 million. In addition, we issued
a $10 million promissory note to JEDI as part of the merger
consideration. See Enron Related Matters
and JEDI Term Promissory Note. Net
proceeds from a private equity placement were approximately
$44 million, of which $6 million was used to pay down
the JEDI
73
promissory note with the remainder used to pay down the credit
facility. The JEDI note was fully repaid at its maturity date of
March 2, 2006.
For the years ended December 31, 2005 and 2004, our
interest rate sensitivity for a change in interest rates of
1/8 percent on average outstanding debt under our credit
facility is approximately $0.1 million and
$0.1 million, respectively. The LIBOR rate on which our
bank borrowings are primarily based was 4.69% as of
March 2, 2006.
We had net cash inflows of $1.1 million and
$5.5 million for the six-month periods ended June 30,
2006 and 2005, respectively, and a net cash inflow of
$2.0 million in 2005 compared to a net cash outflow of
$57.6 million in 2004 and a net cash inflow of
$41.8 million in 2003. A discussion of the major components
of cash flows for these periods follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Period from
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
March 3,
|
|
January 1,
|
|
|
|
|
Six Months
|
|
Year Ended
|
|
Year Ended
|
|
2004 to
|
|
2004 to
|
|
Year Ended
|
|
|
Ended June 30,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
March 2,
|
|
December 31,
|
|
|
2006
|
|
2005
|
|
2005
|
|
2004
|
|
2004
|
|
2004
|
|
2003
|
|
|
(In millions)
|
|
Cash flows provided by operating
activities
|
|
$
|
96.1
|
|
|
$
|
72.7
|
|
|
$
|
165.4
|
|
|
$
|
155.5
|
|
|
$
|
135.2
|
|
|
$
|
20.3
|
|
|
$
|
88.9
|
|
Net cash flows from operations increased by $23.4 million
to $96.1 million from $72.7 million for the six-month
periods ended June 30, 2006 and 2005, respectively. The
increase was primarily due to increased operating revenues
attributable to the Forest Gulf of Mexico operations acquired.
Net cash flows from operations included a reduction of
$80.3 million resulting from an increase in capital
expenditure accruals from December 31, 2005 to
June 30, 2006.
Cash flows provided by operating activities in 2005 increased by
$9.9 million compared to 2004. The increase was primarily
due to negative changes in working capital offset by lowered
operating revenues. Cash flows provided by operating activities
in 2004 increased by $66.6 million compared to 2003
primarily due to improved operating results and net income
driven by increased production volumes and higher net oil and
natural gas prices realized by Mariner.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Period from
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
March 3,
|
|
January 1,
|
|
|
|
|
Six Months
|
|
Year Ended
|
|
Year Ended
|
|
2004 to
|
|
2004 to
|
|
Year Ended
|
|
|
Ended June 30,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
March 2,
|
|
December 31,
|
|
|
2006
|
|
2005
|
|
2005
|
|
2004
|
|
2004
|
|
2004
|
|
2003
|
|
|
(In millions)
|
|
Cash flows (used in) provided by
investing activities
|
|
$
|
(204.8
|
)
|
|
$
|
(98.7
|
)
|
|
$
|
(247.8
|
)
|
|
$
|
(148.3
|
)
|
|
$
|
(133.0
|
)
|
|
$
|
(15.3
|
)
|
|
$
|
52.9
|
|
Net cash flows used for investing activities increased to
$204.8 million from $98.7 million for the six-month
periods ended June 30, 2006 and 2005, respectively, due to
increased capital expenditures of $87.3 million primarily
related to our King Kong and NW Nansen deepwater projects as
well as development drilling in our West Texas fields. As
described above, capital expenditure accruals of
$80.3 million are reflected as a component of working
capital changes.
Cash flows used in investing activities in 2005 increased by
$99.5 million compared to 2004 due to increased capital
expenditures in 2005. Cash flows used in investing activities in
2004 increased by $201.2 million compared to 2003 due to
increased capital expenditures in 2004 and the sale of assets in
prior years.
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Period from
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
March 3,
|
|
January 1,
|
|
|
|
|
Six Months
|
|
Year Ended
|
|
Year Ended
|
|
2004 to
|
|
2004 to
|
|
Year Ended
|
|
|
Ended June 30,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
March 2,
|
|
December 31,
|
|
|
2006
|
|
2005
|
|
2005
|
|
2004
|
|
2004
|
|
2004
|
|
2003
|
|
|
(In millions)
|
|
Cash flows (used in) provided by
financing activities
|
|
$
|
109.8
|
|
|
$
|
31.5
|
|
|
$
|
84.4
|
|
|
$
|
(64.9
|
)
|
|
$
|
(64.9
|
)
|
|
|
|
|
|
$
|
(100.0
|
)
|
Net cash provided by financing activities was
$109.8 million for the six-month period ended June 30,
2006 compared to net cash provided by financing activities of
$31.5 million for the same period in 2005. Financings in
2006 were primarily used to fund the Forest transaction and
capital expenditures in excess of current cash flows. Mariner
also paid the remaining balance of the JEDI term note on
March 2, 2006.
Cash flows provided by financing activities in 2005 were
primarily the result of proceeds from a private equity offering
in March 2005 ($44 million) and net borrowings under our
revolving credit facility ($47 million). Cash flows used in
financing activities in 2004 decreased by $35.1 million
compared to 2003 as a result of a $166 million dividend to
our former indirect parent used to help repay a term loan to an
affiliate of Enron Corp. and the placement of our revolving
credit facility.
Commodity
Prices and Related Hedging Activities
The energy markets have historically been very volatile, and we
can reasonably expect that oil and gas prices will be subject to
wide fluctuations in the future. If an effort to reduce the
effects of the volatility of the price of oil and natural gas on
our operations, management has adopted a policy of hedging oil
and natural gas prices from time to time primarily through the
use of commodity price swap agreements and costless collar
arrangements. While the use of these hedging arrangements limits
the downside risk of adverse price movements, it also limits
future gains from favorable movements. In addition, forward
price curves and estimates of future volatility are used to
assess and measure the ineffectiveness of our open contracts at
the end of each period. If open contracts cease to qualify for
hedge accounting, the mark to market change in fair value is
recognized in the income statement. Loss of hedge accounting and
cash flow designation will cause volatility in earnings. The
fair values we report in our financial statements change as
estimates are revised to reflect actual results, changes in
market conditions or other factors, many of which are beyond our
control.
The cash losses on contracts settled for natural gas and oil
produced during the six-month period ended June 30, 2006
was $11.8 million. A $3.9 million non-cash gain was
also recorded for the six-month period ended June 30, 2006
relating to the hedges acquired through the Forest transaction.
Additionally, an unrealized loss of $1.0 million was
recognized for the six-month period ended June 30, 2006
related to the ineffective portion of open contracts that were
not eligible for deferral under SFAS 133 due primarily to
the basis differentials between the contract price, which is
NYMEX-based for oil and Henry Hub-based for gas, and the indexed
price at the point of sale.
As of June 30, 2006, Mariner had the following hedge
contracts outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2006 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
862,960
|
|
|
$
|
72.41
|
|
|
$
|
(2.6
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
9,752,000
|
|
|
|
6.92
|
|
|
|
(0.2
|
)
|
January 1
March 31, 2007
|
|
|
3,690,010
|
|
|
|
9.30
|
|
|
|
(4.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(6.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 Fair Value
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
126,960
|
|
|
$
|
32.65
|
|
|
$
|
41.52
|
|
|
$
|
(4.2
|
)
|
January 1
December 31, 2007
|
|
|
1,533,775
|
|
|
|
59.13
|
|
|
|
82.85
|
|
|
|
(7.3
|
)
|
January 1
December 31, 2008
|
|
|
1,080,020
|
|
|
|
61.63
|
|
|
|
86.80
|
|
|
|
(0.2
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
3,703,920
|
|
|
|
5.78
|
|
|
|
7.85
|
|
|
|
(1.8
|
)
|
January 1
December 31, 2007
|
|
|
14,106,750
|
|
|
|
6.87
|
|
|
|
11.82
|
|
|
|
(9.0
|
)
|
January 1
December 31, 2008
|
|
|
12,347,000
|
|
|
|
7.83
|
|
|
|
14.60
|
|
|
|
3.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(18.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005, Mariner had the following hedge
contracts outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2005 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2006
|
|
|
140,160
|
|
|
$
|
29.56
|
|
|
|
(4.7
|
)
|
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2006
|
|
|
1,827,547
|
|
|
|
5.53
|
|
|
|
(9.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(14.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Fair Value
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2006
|
|
|
251,850
|
|
|
$
|
32.65
|
|
|
$
|
41.52
|
|
|
|
(5.3
|
)
|
January
1 December 31, 2007
|
|
|
202,575
|
|
|
|
31.27
|
|
|
|
39.83
|
|
|
|
(4.7
|
)
|
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2006
|
|
|
7,347,450
|
|
|
|
5.78
|
|
|
|
7.85
|
|
|
|
(22.3
|
)
|
January
1 December 31, 2007
|
|
|
5,310,750
|
|
|
|
5.49
|
|
|
|
7.22
|
|
|
|
(16.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(49.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2004, Mariner had the following hedge
contracts outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2004 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2005
|
|
|
606,000
|
|
|
$
|
26.15
|
|
|
$
|
(10.0
|
)
|
January
1 December 31, 2006
|
|
|
140,160
|
|
|
|
29.56
|
|
|
|
(1.5
|
)
|
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2005
|
|
|
8,670,159
|
|
|
|
5.41
|
|
|
|
(7.0
|
)
|
January 1
December 31, 2006
|
|
|
1,827,547
|
|
|
|
5.53
|
|
|
|
(1.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(20.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 Fair Value
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2005
|
|
|
229,950
|
|
|
$
|
35.60
|
|
|
$
|
44.77
|
|
|
$
|
(0.4
|
)
|
January
1 December 31, 2006
|
|
|
251,850
|
|
|
|
32.65
|
|
|
|
41.52
|
|
|
|
(0.7
|
)
|
January
1 December 31, 2007
|
|
|
202,575
|
|
|
|
31.27
|
|
|
|
39.83
|
|
|
|
(0.6
|
)
|
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1 December 31, 2005
|
|
|
2,847,000
|
|
|
|
5.73
|
|
|
|
7.80
|
|
|
|
0.4
|
|
January
1 December 31, 2006
|
|
|
3,514,950
|
|
|
|
5.37
|
|
|
|
7.35
|
|
|
|
(0.3
|
)
|
January
1 December 31, 2007
|
|
|
1,806,750
|
|
|
|
5.08
|
|
|
|
6.26
|
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to June 30, 2006, Mariner entered into the
following hedging transactions:
|
|
|
|
|
|
|
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
October 1
December 31, 2006
|
|
|
260,360
|
|
|
$
|
72.35
|
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
October 1
December 31, 2006
|
|
|
5,451,000
|
|
|
$
|
9.16
|
|
January 1, 2007
December 31, 2007
|
|
|
12,156,323
|
|
|
$
|
9.79
|
|
January 1, 2008
September 30, 2008
|
|
|
3,059,689
|
|
|
$
|
9.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2007
|
|
|
498,914
|
|
|
$
|
62.00
|
|
|
$
|
88.40
|
|
January 1
December 31, 2008
|
|
|
115,475
|
|
|
|
62.00
|
|
|
|
86.85
|
|
We have reviewed the financial strength of our hedge
counterparties and believe our credit risk to be minimal. Under
the terms of some of these transactions, from time to time we
may be required to provide security in the form of cash or
letters of credit to our counterparties. As of June 30,
2006, December 31, 2005 and December 31, 2004, we had
no deposits for collateral with our counterparties.
The following table sets forth the results of third party
hedging transactions during the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Year Ended December 31,
|
|
|
|
June 30, 2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in millions)
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity settled (MMBtus)
|
|
|
11,638,000
|
|
|
|
15,917,159
|
|
|
|
18,823,063
|
|
|
|
25,520,000
|
|
Decrease in Natural Gas Sales
|
|
$
|
(3.3
|
)
|
|
$
|
(33.0
|
)
|
|
$
|
(10.8
|
)
|
|
$
|
(27.1
|
)
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity settled (Mbbls)
|
|
|
395
|
|
|
|
836
|
|
|
|
1,554
|
|
|
|
730
|
|
Decrease in Crude Oil Sales
|
|
$
|
(5.6
|
)
|
|
$
|
(20.8
|
)
|
|
$
|
(16.9
|
)
|
|
$
|
(5.0
|
)
|
The cash losses on contracts settled for natural gas and oil
produced during the six-month period ended June 30, 2006
was $11.8 million. A $3.9 million non-cash gain was
also recorded for the six-month period ended June 30, 2006
relating to the hedges acquired through the Forest transaction.
Additionally, an unrealized loss of $1.0 million was
recognized for the six-month period ended June 30, 2006
related to the ineffective portion of open contracts that were
not eligible for deferral under SFAS 133 due primarily to
the basis differentials between the contract price, which is
NYMEX-based for oil and Henry Hub-based for gas, and the indexed
price at the point of sale. In accordance with purchase price
accounting implemented at the time of
77
the merger of our former indirect parent on March 2, 2004,
we recorded the
mark-to-market
liability of our hedge contracts at such date totaling
$12.4 million as a liability on our balance sheet. See
Critical Accounting Policies and
Estimates Hedging Program. For the years ended
December 31, 2005 and 2004, $4.5 million and
$7.9 million, respectively, of the $53.8 million and
$27.7 million total decrease in natural gas and oil sales,
respectively, of cash hedge losses relate to the liability
recorded at the time of the merger.
Interest
Rate Hedges
Borrowings under our revolving credit the facility, discussed
above, mature on March 2, 2010, and bear interest at either
a LIBOR-based rate or a prime-based rate, at our option, plus a
specified margin. Both options expose us to risk of earnings
loss due to changes in market rates. We have not entered into
interest rate hedges that would mitigate such risk.
Contractual
Commitments
We have numerous contractual commitments in the ordinary course
of business, debt service requirements and operating lease
commitments. The following table summarizes these commitments at
June 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than
|
|
|
1-3
|
|
|
3-5
|
|
|
More Than
|
|
|
|
Total
|
|
|
One Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In millions)
|
|
|
Debt obligations(1)
|
|
$
|
457.0
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
157.0
|
|
|
$
|
300.0
|
|
Interest obligations(2)
|
|
|
155.1
|
|
|
|
22.5
|
|
|
|
45.0
|
|
|
|
45.0
|
|
|
|
42.6
|
|
Operating leases
|
|
|
7.3
|
|
|
|
1.4
|
|
|
|
2.3
|
|
|
|
1.3
|
|
|
|
2.3
|
|
Abandonment liabilities
|
|
|
231.8
|
|
|
|
43.1
|
|
|
|
41.1
|
|
|
|
43.8
|
|
|
|
103.8
|
|
Derivative liability
|
|
|
25.7
|
|
|
|
11.0
|
|
|
|
14.7
|
|
|
|
|
|
|
|
|
|
Other liabilities
|
|
|
242.3
|
|
|
|
231.3
|
|
|
|
11.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash commitments
|
|
$
|
1,119.2
|
|
|
$
|
309.3
|
|
|
$
|
114.1
|
|
|
$
|
247.1
|
|
|
$
|
448.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As of June 30, 2006, we had incurred debt obligations under
our secured credit facility and the senior unsecured notes that
are due on March 2, 2010 and April 15, 2013,
respectively. |
|
(2) |
|
Interest obligations represent interest due on the senior
unsecured notes at 7.5%. Future interest obligations under our
credit facility are uncertain, due to the variable interest rate
on fluctuating balances. Based on a 8.0% weighted average
interest rate on amounts outstanding under our amended and
restated credit facility as of June 30, 2006,
$13.4 million, $26.9 million and $9.0 million
would be due under the credit facility in less than one year,
1-3 years and 3-5 years, respectively. |
Certain MMS Leases. Each of Mariner and its
subsidiary, Mariner Energy Resources, Inc., owns numerous
properties in the Gulf of Mexico. Certain of these properties
were leased from the MMS subject to the Outer Continental Shelf
Deep Water Royalty Relief Act (the RRA). The RRA
relieved the obligation to pay royalties on certain leases until
a designated volume is produced. Two of these leases held by
Mariner and one held by its subsidiary contained language that
limited royalty relief if commodity prices exceeded
predetermined levels. Since 2000, commodity prices have exceeded
the predetermined levels, except in 2002. Mariner and its
subsidiary believe the MMS did not have the authority to set
pricing limits in these leases and have withheld payment of
royalties on the leases while disputing the MMS authority
in two pending proceedings. Mariner has recorded a liability for
100% of the exposure on its two leases, which at June 30,
2006 was $18.8 million. In April 2005, the MMS denied
Mariners administrative appeal of the MMS April 2001
order asserting royalties were due because price limits had been
exceeded. In October 2005, Mariner filed suit in the
U.S. District Court for the Southern District of Texas
seeking judicial review of the dismissal. Upon motion of the
MMS, Mariners lawsuit was dismissed on procedural grounds.
In August 2006, Mariner filed an appeal of such dismissal.
Mariner had also filed an administrative appeal of a December
2005 order of the MMS demanding royalties for calendar year 2004
under the same leases at issue in the April 2001 MMS order.
However, the MMS withdrew such order, rendering the appeal moot.
Thereafter, in May 2006, the MMS issued an order asserting price
limits were exceeded in calendar years 2001, 2003 and 2004 and,
accordingly,
78
that royalties were due under such leases on oil and gas
produced in those years. Mariner has filed and is pursuing an
administrative appeal of that order.
The potential liability of Mariner Energy Resources, Inc. under
its lease subject to the RRA containing such commodity price
threshold language is approximately $1.8 million as of
June 30, 2006. This potential liability relates to
production from the lease commencing July 1, 2005, the
effective date of Mariners acquisition of Mariner Energy
Resources, Inc. A reserve for this possible liability will be
made when deemed appropriate. The MMS has not yet made demand
for non-payment of royalties alleged to be due for calendar
years subsequent to 2004 on the basis of price thresholds being
exceeded.
Off-Balance
Sheet Arrangements
Transportation Contract In 1999, Mariner
constructed a
29-mile
flowline from a third party platform to the Mississippi Canyon
674 subsea well. After commissioning, MEGS LLC, an Enron
affiliate, purchased the flowline from Mariner and its joint
interest partner. In addition, Mariner entered into a firm
transportation contract with MEGS LLC at a rate of
$0.26 per MMBtu to transport Mariners share of
approximately 130,000,000 MMbtus of natural gas from the
commencement of production through March 2009. Mariners
working interest in the well is 51%. For the year ended
December 31, 2003, Mariner paid $1.9 million on this
contract. The remaining volume commitment was
14,707,107 MMbtus or $3.8 million net to Mariner.
Pursuant to the contract, Mariner was required to deliver
minimum quantities through the flowline or be subject to minimum
monthly payment requirements.
On May 10, 2004, Mariner and the other 49% working interest
owner in the Mississippi Canyon 674 well purchased the
flowline from MEGS LLC for an adjusted purchase price of
approximately $3.8 million, of which approximately
$1.9 million was paid by Mariner, and terminated the
transportation contract and associated liability. Accordingly,
we currently have no off-balance sheet arrangements.
On March 2, 2006, Mariner obtained a $40 million
letter of credit under its senior secured letter of credit
facility. The letter of credit was issued in favor of Forest to
secure our performance of our obligations under an existing
drill-to-earn
program. This letter of credit is not included as a use of
Mariners borrowing base availability. The amount of the
letter of credit is to reduce periodically, with the reduction
amount depending upon the number of wells drilled. Based upon
the number of wells drilled as of September 30, 2006, the
first reduction is expected in October 2006.
Recent
Accounting Pronouncements
In September 2005, the Emerging Issues Task Force (EITF) reached
a consensus on Issue
No. 04-13,
Accounting for Purchases and Sales of Inventory with
the Same Counterparty. EITF
Issue 04-13
requires that purchases and sales of inventory with the same
counterparty in the same line of business should be accounted
for as a single non-monetary exchange, if entered into in
contemplation of one another. The consensus is effective for
inventory arrangements entered into, modified or renewed in
interim or annual reporting periods beginning after
March 15, 2006. We do not expect the adoption of this EITF
Issue to have a material impact on our consolidated financial
position, results of operations or cash flows.
In July 2006, the FASB issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income
Taxes. FIN No. 48 clarifies
SFAS No. 109, Accounting for Income Taxes, and
requires us to evaluate our tax positions for all jurisdictions
and all years where the statute of limitations has not expired.
FIN No. 48 requires companies to meet a
more-likely-than-not threshold (i.e. greater than a
50 percent likelihood of being sustained under examination)
prior to recording a benefit for their tax positions.
Additionally, for tax positions meeting this
more-likely-than-not threshold, the amount of
benefit is limited to the largest benefit that has a greater
than 50 percent probability of being realized upon ultimate
settlement. The cumulative effect of applying the provisions of
the new interpretation will be recorded as an adjustment to the
beginning balance of retained earnings, or other components of
stockholders equity, as appropriate, in the period of
adoption. We will adopt the provisions of this interpretation
effective January 1, 2007, and are currently evaluating the
impact, if any, that this interpretation will have on our
financial statements.
79
BUSINESS
Mariner Energy, Inc. is an independent oil and gas exploration,
development and production company with principal operations in
the Gulf of Mexico, both shelf and deepwater, and in West Texas.
Our management has significant expertise and a successful
operating track record in these areas. In the three-year period
ended December 31, 2005, we added approximately 280 Bcfe of
proved reserves and produced approximately 100 Bcfe, while
deploying approximately $475 million of capital on
acquisitions, exploration and development.
Our primary operating strategy is to generate high-quality
exploration and development projects, which enables us to add
value through the drill bit. Our expertise in project generation
also facilitates our participation in high-quality projects
generated by other operators. We will also pursue acquisitions
of producing assets that have the potential to provide
acceptable risk-adjusted rates of return and further reserve
additions through exploration, exploitation, and development
opportunities. We target a balanced exposure to development,
exploitation and exploration opportunities, both offshore and
onshore and seek to maintain a moderate risk profile.
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources, Inc., which we refer to as Forest
Energy Resources. As a result of this merger, we acquired the
Gulf of Mexico operations of Forest Oil Corporation (NYSE: FST),
which we refer to as the Forest Gulf of Mexico operations. As of
December 31, 2005, we had 338 Bcfe of estimated proved
reserves, of which approximately 62% were natural gas, and 38%
were oil and condensate, and 50% of which was proved developed.
Pro forma for the merger transaction, as of December 31,
2005, we had 644 Bcfe of estimated proved reserves, of
which approximately 68% were natural gas and 32% were oil and
condensate, and 56% of which was proved developed.
Our production for 2005 was approximately 29 Bcfe, or
80 MMcfe per day on average, and 95 Bcfe, or
260 MMcfe per day on average, pro forma for the merger.
During the year ended December 31, 2005, our pro forma
EBITDA was approximately $438.6 million, including
$25.7 million of non-cash compensation expense related to
restricted stock and stock options granted in 2005, but
excluding general and administrative expenses of the Forest Gulf
of Mexico operations. Our production for the six months ended
June 30, 2006 was approximately 32 Bcfe, or
176 MMcfe per day on average, and pro forma for the merger,
40 Bcfe, or 219 MMcfe per day on average. During the
six months ended June 30, 2006, our EBITDA was
approximately $190.6 million, and pro forma for the merger,
approximately $241.6 million, in each case, including a
$7.9 million reduction for non-cash compensation expense
related to restricted stock and stock options. We believe the
overhead costs associated with the Forest Gulf of Mexico
operations in 2006 will be approximately $6.4 million, net
of capitalized amounts. See footnote 1 on page 15 for
our definition of EBITDA and a reconciliation of net income to
EBITDA.
80
The following table sets forth certain information with respect
to our estimated proved reserves, production and acreage by
geographic area as of December 31, 2005. Reserve volumes
and values were determined under the method prescribed by the
SEC which requires the application of period-end prices and
costs held constant throughout the projected reserve life.
Proved reserve estimates do not include any value for probable
or possible reserves which may exist, nor do they include any
value for undeveloped acreage. The proved reserve estimates
represent our net revenue interest in our properties. The
reserve information for Mariner as of December 31, 2005 is
based on estimates made in a reserve report prepared by Ryder
Scott.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production for
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
Estimated Proved
|
|
|
|
|
|
December 31
|
|
|
|
Reserve Quantities
|
|
|
|
|
|
2005
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
Total Net
|
|
|
(Natural Gas
|
|
|
|
(MMbbls)
|
|
|
(Bcf)
|
|
|
(Bcfe)
|
|
|
Acreage
|
|
|
Equivalent (Bcfe))
|
|
|
West Texas
|
|
|
16.7
|
|
|
|
105.5
|
|
|
|
205.5
|
|
|
|
31,199
|
|
|
|
6.6
|
|
Gulf of Mexico Deepwater(1)
|
|
|
4.7
|
|
|
|
83.2
|
|
|
|
111.1
|
|
|
|
185,271
|
|
|
|
11.8
|
|
Gulf of Mexico Shelf(2)
|
|
|
0.3
|
|
|
|
19.0
|
|
|
|
21.0
|
|
|
|
124,180
|
|
|
|
10.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.7
|
|
|
|
207.7
|
|
|
|
337.6
|
|
|
|
340,650
|
|
|
|
29.1
|
|
Proved Developed Reserves
|
|
|
9.6
|
|
|
|
110.0
|
|
|
|
167.4
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service). |
|
(2) |
|
Shelf refers to water depths less than 1,300 feet and
includes an insignificant amount of Gulf Coast onshore
properties. |
The following table sets forth certain information with respect
to our estimated proved reserves, production and acreage by
geographic area on a pro forma basis for our merger with Forest
Energy Resources as of December 31, 2005. The reserve
information as of December 31, 2005 for the Forest Gulf of
Mexico operations is based on estimates made by internal staff
engineers of Forest, which estimates were audited by Ryder
Scott. This information is presented on a pro forma basis,
giving effect to our merger with Forest Energy Resources as
though it had been consummated on December 31, 2005. We
consummated the merger on March 2, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production for
|
|
|
|
Pro Forma
|
|
|
|
|
|
Year Ended
|
|
|
|
Estimated Proved
|
|
|
|
|
|
December 31
|
|
|
|
Reserve Quantities
|
|
|
Total
|
|
|
2005
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
Net
|
|
|
(Natural Gas
|
|
|
|
(MMbbls)
|
|
|
(Bcf)
|
|
|
(Bcfe)
|
|
|
Acreage
|
|
|
Equivalent (Bcfe))
|
|
|
West Texas
|
|
|
16.7
|
|
|
|
105.5
|
|
|
|
205.5
|
|
|
|
31,199
|
|
|
|
6.6
|
|
Gulf of Mexico Deepwater(1)
|
|
|
4.8
|
|
|
|
95.7
|
|
|
|
124.5
|
|
|
|
241,320
|
|
|
|
14.0
|
|
Gulf of Mexico Shelf(2)
|
|
|
12.7
|
|
|
|
237.6
|
|
|
|
313.7
|
|
|
|
652,086
|
|
|
|
74.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
34.2
|
|
|
|
438.8
|
|
|
|
643.7
|
|
|
|
924,605
|
|
|
|
94.9
|
|
Proved Developed Reserves
|
|
|
18.4
|
|
|
|
252.1
|
|
|
|
362.3
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service). |
|
(2) |
|
Shelf refers to water depths less than 1,300 feet and
includes an insignificant amount of Gulf Coast onshore
properties. |
Forest
Gulf of Mexico Merger
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources. Prior to the consummation of the
merger, Forest transferred and contributed the assets and
certain liabilities associated with its Gulf of Mexico
operations to Forest Energy Resources. Immediately prior to the
merger, Forest
81
distributed all of the outstanding shares of Forest Energy
Resources to Forest shareholders on a pro rata basis. Forest
Energy Resources then merged with a newly-formed subsidiary of
Mariner, became a new wholly-owned subsidiary of Mariner, and
changed its name to Mariner Energy Resources, Inc. Immediately
following the merger, approximately 59% of Mariner common stock
was held by shareholders of Forest and approximately 41% of
Mariner common stock was held by the pre-merger stockholders of
Mariner.
Forest Energy Resources had approximately 306 Bcfe of
estimated proved reserves as of December 31, 2005, of which
approximately 76% were natural gas, and 24% were oil and
condensate. The reserves and operations acquired from Forest are
concentrated in the shelf and deep shelf of the Gulf of Mexico
and represent a significant addition to Mariners asset
portfolio in those areas of operation.
We believe our acquisition of the Forest Gulf of Mexico
operations and the scale they bring to our business has further
moderated our risk profile, provided many exploration,
exploitation and development opportunities, enhanced our ability
to participate in prospects generated by other operators, and
added a significant cash flow generating resource that has
improved our ability to compete effectively in the Gulf of
Mexico and fund exploration activities and acquisitions. We
believe we are well-positioned to optimize the Forest Energy
Resources assets through aggressive and timely exploitation.
Our
Strategy and Our Competitive Strengths
Our
Strategy
The principal elements of our operating strategy include:
Generating and pursuing high-quality
prospects. We expect to continue our strategy of
growth through the drill bit by continuing to identify and
develop high-impact shelf, deep shelf and deepwater projects in
the Gulf of Mexico. Our technical team has significant expertise
in, and a successful track record of achieving growth by,
generating prospects internally and selectively participating in
prospects generated by other operators. We believe the Gulf of
Mexico is an area that offers substantial growth opportunities,
and our acquisition of the Forest Gulf of Mexico operations has
more than doubled our existing undeveloped acreage position in
the Gulf, providing numerous additional exploration,
exploitation and development opportunities.
Maintaining a moderate risk profile. We seek
to manage our risk profile by targeting a balanced exposure to
development, exploitation and exploration opportunities. For
example, we intend to continue to develop and seek to expand our
West Texas asset base, which contributes stable cash flows and
long-lived reserves to our portfolio as a counterbalance to our
high-impact, high-production Gulf of Mexico assets. We also seek
to mitigate and diversify our risk in drilling projects by
selling partial or entire interests in projects to industry
partners or by entering into arrangements with industry partners
in which they agree to pay a disproportionate share of drilling
costs and compensate us for expenses incurred in prospect
generation. We also enter into trades or farm-in transactions
whereby we acquire interests in third-party generated prospects,
thereby gaining exposure to a greater number of prospects. We
expect more opportunities to participate in these prospects in
the future as a result of our larger scale and increased cash
flow from the Forest Gulf of Mexico operations.
Pursuing opportunistic acquisitions. Until
2005, we grew our reserves primarily through the drill bit. In
2005 we added significant proved reserves primarily through
acquisitions in West Texas and subsequently in March 2006,
through the acquisition of the Forest Gulf of Mexico operations.
As part of our growth strategy, we will seek to continue to
acquire producing assets that have the potential to provide
acceptable risk-adjusted rates of return and further reserve
additions through exploration, exploitation and development
opportunities.
82
Our
Competitive Strengths
We believe our core resources and strengths include:
Our high-quality assets with geographic and geological
diversity. Our assets and operations are
diversified among the Gulf of Mexico shelf, deep shelf and
deepwater, and West Texas. Our asset portfolio provides a
balanced exposure to long-lived West Texas reserves, Gulf of
Mexico shelf growth opportunities and high-impact deepwater
prospects.
Our large inventory of prospects. We believe
we have significant potential for growth through the development
of our existing asset base. The acquisition of the Forest Gulf
of Mexico operations more than doubled our existing undeveloped
acreage position in the Gulf of Mexico to approximately
450,000 net acres and increased our total net leasehold
acreage offshore to nearly one million acres, providing numerous
exploration, exploitation and development opportunities. As of
September 30, 2006, we have an inventory of approximately
890 drilling locations in West Texas, which we believe would
require approximately six years to drill at our current rate.
These include approximately 430 locations pertaining to
98 Bcfe of estimated net proved undeveloped reserves and
approximately 460 other locations.
Our successful track record of finding and developing oil and
gas reserves. We have demonstrated our expertise
in finding and developing additional proved reserves. In the
three-year period ended December 31, 2005, we deployed
approximately $475 million of capital on acquisitions,
exploration and development, while adding approximately
280 Bcfe of proved reserves and producing approximately
100 Bcfe.
Our depth of operating experience. Our team of
41 geoscientists, engineers, geologists and other technical
professionals and landmen as of September 30, 2006 average
more than 22 years of experience in the exploration and
production business (including extensive experience in the Gulf
of Mexico), much of it with major oil companies. The addition of
experienced Forest personnel to Mariners team of technical
professionals has further enhanced our ability to generate and
maintain an inventory of high-quality drillable prospects and to
further develop and exploit our assets. Mariners technical
team has also proven to be an effective and efficient operator
in West Texas, as evidenced by our successful production and
reserve growth there in recent years.
Our technology and production techniques. Our
team of geoscientists currently has access to seismic data from
multiple, recent
vintage 3-D
seismic databases covering more than 7,000 blocks in the Gulf of
Mexico that we intend to continue to use to develop prospects on
acreage being evaluated for leasing and to develop and further
refine prospects on our expanded acreage position. We also have
extensive experience and a successful track record in the use of
subsea tieback technology to connect offshore wells to existing
production facilities. This technology facilitates production
from offshore properties without the necessity of fabrication
and installation of platforms and top-side facilities that
typically are more costly and require longer lead times. We
believe the use of subsea tiebacks in appropriate projects
enables us to bring production online more quickly, makes target
prospects more profitable and allows us to exploit reserves that
may otherwise be considered non-commercial because of the high
cost of infrastructure. In the Gulf of Mexico, in the three
years ended December 31, 2005, we were directly involved in
14 projects (five of which we operated) utilizing subsea tieback
systems in water depths ranging from 475 feet to more than
6,700 feet. As of September 30, 2006, we had 18 subsea
wells in water depths ranging from 450 feet to more than
4,700 feet. These wells were tied back to 13 host
production facilities for production processing. An additional
nine wells in water depths ranging from 465 feet to more
than 6,800 feet were then under development for tieback to
five additional host production facilities.
83
Properties
We currently own oil and gas properties, producing and
non-producing, onshore in Texas and offshore in the Gulf of
Mexico, primarily in federal waters. Our largest properties
(including the largest properties we acquired in our merger with
Forest Energy Resources), based on the present value of
estimated future net proved reserves as of December 31,
2005, are shown in the following table.
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Date
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|
Estimated
|
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|
Mariner
|
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Approximate
|
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Gross
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Production
|
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Proved
|
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Working
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Water Depth
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Producing
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|
|
Commenced/
|
|
|
Reserves
|
|
|
|
|
|
Standardized
|
|
|
|
Operator
|
|
Interest (%)
|
|
|
(Feet)
|
|
|
Wells(1)
|
|
|
Expected
|
|
|
(Bcfe)
|
|
|
PV10 Value
|
|
|
Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ In millions)(2)
|
|
|
($ In millions)
|
|
|
West Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aldwell Unit
|
|
Mariner
|
|
|
66.5
|
(3)
|
|
|
Onshore
|
|
|
|
246
|
|
|
|
*
|
|
|
|
120.7
|
|
|
$
|
367.0
|
|
|
|
|
|
Tamarack/Spraberry Properties
|
|
Tamarack
|
|
|
35.0
|
(4)
|
|
|
Onshore
|
|
|
|
187
|
|
|
|
*
|
|
|
|
67.8
|
|
|
|
103.2
|
|
|
|
|
|
Gulf of Mexico
Deepwater:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi Canyon 296/252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Rigel)
|
|
Dominion
|
|
|
22.5
|
|
|
|
5,200
|
|
|
|
0
|
(5)
|
|
|
2006
|
|
|
|
22.5
|
|
|
|
161.4
|
|
|
|
|
|
Atwater Valley 426 (Bass Lite)
|
|
Mariner
|
|
|
38.75
|
(6)
|
|
|
6,800
|
|
|
|
0
|
|
|
|
2008
|
|
|
|
32.3
|
|
|
|
137.9
|
|
|
|
|
|
Viosca Knoll 917/961/962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Swordfish)
|
|
Mariner(7)
|
|
|
15.0
|
|
|
|
4,700
|
|
|
|
2
|
|
|
|
2005
|
|
|
|
12.9
|
|
|
|
101.7
|
|
|
|
|
|
Mississippi Canyon 718 (Pluto)(8)
|
|
Mariner
|
|
|
51.0
|
|
|
|
2,830
|
|
|
|
0
|
|
|
|
1999
|
|
|
|
9.0
|
|
|
|
69.3
|
|
|
|
|
|
Green Canyon 646 (Daniel Boone)
|
|
W&T Offshore
|
|
|
40.0
|
|
|
|
4,300
|
|
|
|
0
|
|
|
|
2008
|
|
|
|
16.4
|
|
|
|
61.8
|
|
|
|
|
|
Green Canyon 516 (Yosemite)
|
|
ENI
|
|
|
44.0
|
|
|
|
3,900
|
|
|
|
1
|
|
|
|
2002
|
|
|
|
7.8
|
|
|
|
53.9
|
|
|
|
|
|
East Breaks 420**
|
|
Noble
|
|
|
50.0
|
|
|
|
2,560
|
|
|
|
1
|
|
|
|
2002
|
|
|
|
13.4
|
|
|
|
75.8
|
|
|
|
|
|
Gulf of Mexico Shelf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East Cameron 14**
|
|
Mariner
|
|
|
50.0
|
|
|
|
25
|
|
|
|
2
|
|
|
|
*
|
|
|
|
15.2
|
|
|
|
91.5
|
|
|
|
|
|
Eugene Island 292**
|
|
Mariner
|
|
|
45.0
|
|
|
|
195
|
|
|
|
8
|
|
|
|
*
|
|
|
|
8.2
|
|
|
|
54.7
|
|
|
|
|
|
Eugene Island 53**
|
|
Mariner
|
|
|
50.0
|
(9)
|
|
|
40
|
|
|
|
4
|
|
|
|
*
|
|
|
|
10.4
|
|
|
|
78.1
|
|
|
|
|
|
High Island 116**
|
|
Mariner
|
|
|
98.9
|
(10)
|
|
|
45
|
|
|
|
2
|
|
|
|
*
|
|
|
|
9.7
|
|
|
|
52.7
|
|
|
|
|
|
Ship Shoal 26**
|
|
Mariner
|
|
|
100.0
|
|
|
|
10
|
|
|
|
1
|
|
|
|
*
|
|
|
|
7.2
|
|
|
|
41.5
|
|
|
|
|
|
South Marsh Island 18**
|
|
Mariner
|
|
|
100.0
|
|
|
|
75
|
|
|
|
1
|
|
|
|
1993
|
|
|
|
9.5
|
|
|
|
50.6
|
|
|
|
|
|
South Pass 24-NCOC**
|
|
Mariner
|
|
|
100.0
|
|
|
|
10
|
|
|
|
15
|
|
|
|
*
|
|
|
|
23.5
|
|
|
|
103.8
|
|
|
|
|
|
Vermilion 14**
|
|
Mariner
|
|
|
100.0
|
|
|
|
20
|
|
|
|
16
|
|
|
|
*
|
|
|
|
32.8
|
|
|
|
177.7
|
|
|
|
|
|
Vermilion 380**
|
|
Mariner
|
|
|
55.0-100.0
|
|
|
|
320
|
|
|
|
5
|
|
|
|
*
|
|
|
|
11.4
|
|
|
|
59.2
|
|
|
|
|
|
West Cameron 110/SE/4 111**
|
|
BP/Amoco(11)
|
|
|
37.5
|
(11)
|
|
|
40.5
|
|
|
|
5
|
|
|
|
*
|
|
|
|
9.0
|
|
|
|
51.9
|
|
|
|
|
|
West Cameron 111/112**
|
|
Mariner
|
|
|
55.0
|
|
|
|
43.1
|
|
|
|
1
|
|
|
|
2004
|
|
|
|
6.5
|
|
|
|
49.8
|
|
|
|
|
|
West Cameron 205**
|
|
Mariner
|
|
|
100.0
|
|
|
|
50
|
|
|
|
1
|
|
|
|
*
|
|
|
|
5.7
|
|
|
|
41.9
|
|
|
|
|
|
Other Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
48.2
|
|
|
|
225.6
|
|
|
|
|
|
Other Properties (Forest pro
forma)**
|
|
|
|
|
|
|
|
|
|
|
|
|
344
|
|
|
|
|
|
|
|
143.6
|
|
|
|
840.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
935
|
|
|
|
|
|
|
|
643.7
|
|
|
$
|
3,051.8
|
|
|
$
|
2,201.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Production commenced twenty or more years ago. |
|
** |
|
Pro forma properties from Forest Gulf of Mexico operations. |
|
(1) |
|
Wells producing or capable of producing as of December 31,
2005. |
84
|
|
|
(2) |
|
Please see Estimated Proved Reserves for
a definition of PV10 and a reconciliation of PV10 to the
standardized measure of discounted future net cash flows. |
|
(3) |
|
Mariner operates the field and owns working interests in
individual wells ranging from approximately 33% to 84%. |
|
|
|
(4) |
|
Mariner owns an approximate average 35% working interest in
producing wells. Upon drilling of 150 additional wells,
Mariner will obtain an approximate 35% working interest in the
entire committed acreage. As of September 30, 2006, 88 of
such wells had been drilled. |
|
|
|
(5) |
|
The Rigel Prospect commenced production with one well in the
first quarter of 2006. |
|
(6) |
|
Since December 31, 2005, Mariner has exercised a
preferential right with respect to the property, thereby
increasing its working interest to 42.19%. |
|
(7) |
|
Mariner served as operator until December 2005, at which time
pursuant to certain contractual arrangements, Noble Energy,
Inc., a 60% partner in the project, began serving as operator. |
|
|
|
(8) |
|
This field was shut-in in April 2004 pending the drilling of a
new well and installation of an extension to the existing
infield flowline and umbilical. As a result, as of
December 31, 2005, 8.9 Bcfe of our net proved reserves
attributable to this project were classified as proved behind
pipe reserves. Production from Pluto recommenced in the third
quarter of 2006. |
|
|
|
(9) |
|
Mariner operates the field and owns working interests in
individual wells ranging from approximately 50% to 100%. |
|
(10) |
|
Mariner operates the field and owns working interests in
individual wells ranging from approximately 98.9% to 100%. |
|
(11) |
|
In August 2006, Mariner Energy Resources, Inc. exercised a
preferential right with respect to the West Cameron 110 and
the southeast quarter of West Cameron 111, thereby increasing
its working interest in these properties to 100%, exclusive of
retained interests in depths below 15,000 feet. In
addition, Mariner Energy, Inc. became operator of the interests
its subsidiary owns. |
West
Texas
Aldwell Unit. We operate and own working
interests in individual wells ranging from 33% to 84% (with an
average working interest of approximately 66.5%), in the
18,500-acre Aldwell
Unit. The field is located in the heart of the Spraberry
geologic trend southeast of Midland, Texas, and has produced oil
and gas since 1949. We began our recent redevelopment of the
Aldwell Unit by drilling eight wells in the fourth quarter of
2002, 43 wells in 2003, 54 wells in 2004 and
65 wells in 2005. As of December 31, 2005, there were
a total of 249 wells producing or capable of producing in
the field, and as of June 30, 2006, an additional
16 wells were capable of production.
We have completed construction of our own oil and gas gathering
system and compression facilities in the Aldwell Unit. We began
flowing gas production through the new facilities on
June 1, 2005. We have also entered into contracts with
third parties to provide processing of our natural gas and
transportation of our oil produced in the unit. The gas
arrangement also provides us with the option to sell our gas to
one of four firm or five interruptible sales pipelines versus a
single outlet under the former arrangement. These arrangements
have improved the economics of production from the Aldwell Unit.
Tamarack/Spraberry Properties. Effective in
October 2005, we entered into an agreement covering
approximately 33,000 acres in West Texas, pursuant to
which, upon closing, we acquired an approximate 35% working
interest in approximately 200 existing producing wells effective
November 1, 2005, and committed to drill an additional
150 wells within a four-year period, while funding
$36.5 million of our partners share of drilling costs
for such
150-well
drilling program. We will obtain an assignment of an approximate
35% working interest in the entire committed acreage upon
completion of the
150-well
program. As of September 30, 2006, we have drilled
88 wells under this agreement.
Other Projects and Activity. In December 2004,
we acquired an approximate 50% working interest in two Permian
Basin fields containing approximately 4,000 acres. We believe
the fields contain more than twenty
80-acre
infill drilling locations and that either or both may also have
40-acre
infill drilling
85
opportunities. We have commenced drilling operations in one of
the fields and as of September 30, 2006, have drilled and
completed 23 wells, all of which are productive.
In February 2005, we acquired five producing wells located in
Howard County, Texas, approximately 50 miles north of our
Aldwell Unit. The purchase price was $3.5 million.
In September 2005, we acquired a 100% working interest and 75%
net revenue interest in three producing wells and approximately
3,300 leasehold acres that are held by production in the Canyon
Sawyer Field in Sutton and Schleicher Counties, Texas. The
purchase price was $700,000. Since acquiring the property, we
have refracted two of the three producing wells acquired, and
drilled and completed six new wells as Canyon Sand gas
producers. We expect to complete two additional Canyon Sand
wells in the fourth quarter of 2006. We have approximately 20
additional potential drilling locations on the property.
In December 2005, we acquired an interest in approximately
5,500 acres with an average 84% working interest and
64% net revenue interest in the Spraberry trend area
5-10 miles southwest of our Aldwell Unit. The purchase
price was $5.5 million with an effective date of
August 1, 2005 and included 34 producing wells with the
potential to drill an additional 68 wells on
40-acre
spacing. During the third quarter of 2006, we drilled and
completed five new wells, all of which are productive.
During 2005, our aggregate net capital expenditures for West
Texas were approximately $86 million, and we added
97.2 Bcfe of proved reserves, while producing
6.6 Bcfe. Average daily net production from our
West Texas operations increased from 10.8 MMcfe per
day in 2004 to 17.8 MMcfe per day in 2005, representing an
increase of 64%. As of December 31, 2005, our West Texas
operations included 487 producing wells on 31,199 net
acres, compared to 189 producing wells on 14,448 net acres
at December 31, 2004.
Gulf
of Mexico Deepwater
Mississippi Canyon 296/252 (Rigel). Mariner
generated the Rigel prospect and acquired its interest in
Mississippi Canyon block 296 at a federal offshore Gulf
lease sale in March 1999. Our working interest in Rigel is
22.5%. The project is located approximately 130 miles
southeast of New Orleans, Louisiana, in water depth of
approximately 5,200 feet. A successful exploration well was
drilled on the prospect in 1999. In September 2003, a successful
appraisal well was drilled. This project was developed with a
single subsea well tied back 12 miles to an existing subsea
manifold that is connected to an existing platform. Production
commenced in the first quarter of 2006.
Atwater Valley 426 (Bass Lite). The Bass Lite
project is located in Atwater Valley blocks 380, 381, 382,
425 and 426, approximately 200 miles southeast of New
Orleans in approximately 6,800 feet of water. We have a
42.19% working interest and have been designated operator of
this project. Our working interest partners have approved
development plans. The process of selecting suppliers of major
equipment and services is substantially complete.
Viosca Knoll 917/961/962 (Swordfish). Mariner
generated the Swordfish prospect and entered into a farm-out
agreement with BP in September 2001. We operated Swordfish until
commencement of initial production and own a 15% working
interest. The project is located in the deepwater Gulf of Mexico
105 miles southeast of New Orleans, Louisiana, in a water
depth of approximately 4,700 feet. In November and December
of 2001, we drilled two successful exploration wells on
blocks 917 and 962. In August 2004, a successful appraisal
well found additional reserves on block 961. All wells have
been completed and production commenced in the fourth quarter of
2005.
Mississippi Canyon 718 (Pluto). Mariner
initially acquired an interest in this project in 1997, two
years after gas was discovered on the project. We operate the
property and own a 51% working interest in the project and the
29-mile
flowline that connects to a third-party production platform. We
developed the field with a single subsea well which is located
in the Gulf of Mexico approximately 150 miles southeast of
New Orleans, Louisiana, at a water depth of approximately
2,830 feet. The field was shut-in in April 2004 pending the
drilling of a new well and completion of the installation of an
infield extension to the existing infield flowline and
umbilical. Installation of the subsea facilities is now
complete. During
start-up
operations,
86
a paraffin plug was discovered in the flow-line between the
Pluto field and the host facility. Remediation efforts are
complete and production recommenced in the third quarter of
2006, following completion of the platform operators
repairs to the host facilities necessitated by damage inflicted
by Hurricane Katrina.
Green Canyon 646 (Daniel Boone). Mariner
generated the Daniel Boone prospect and acquired a 100% working
interest in Daniel Boone at a Gulf of Mexico federal offshore
lease sale in July 1998. The project is located in approximately
4,300 feet of water approximately 165 miles south of
New Orleans, Louisiana. Subsequent to the acquisition, Mariner
entered into a farmout agreement retaining a 40% working
interest in the project. A successful exploration well was
drilled in 2003. The project will be developed as a subsea
tieback to existing infrastructure and is expected to commence
production in 2008.
Green Canyon 516 (Yosemite). Mariner generated
the Yosemite prospect and acquired the prospect at a Gulf of
Mexico federal lease sale in 1998. We have a 44% working
interest in this project located in approximately
3,900 feet of water, approximately 150 miles southeast
of New Orleans, Louisiana. In 2001, we drilled an exploratory
well on the prospect, and in February 2002 commenced production
via a
16-mile
subsea tieback to an existing platform which also handles
production from the King Kong field in
Green Canyon 472/473,
in which we own a 50% interest.
East Breaks 420. Forest leased three blocks
located on this property in 1996 and an additional block in
1998. Forest subsequently sold a 50% working interest to Noble.
The property is located in approximately 2,560 feet of
water approximately 174 miles southwest of Cameron,
Louisiana. A successful well was drilled in 2001. The project
was completed with a subsea tieback to existing infrastructure.
Production commenced in June 2002. The property was acquired by
Mariner on March 2, 2006 as part of its merger with Forest
Energy Resources. In the second quarter of 2006, additional
compression was added to the host platform which resulted in an
approximate 50% increase in production.
Other Projects and Activity. In late 2004, we
participated in a successful exploratory well in our
North Black Widow prospect in Ewing Banks 921, which is
located approximately 125 miles south of New Orleans,
Louisiana in approximately 1,700 feet of water. We have a
35% working interest in this project. A development plan for the
North Black Widow prospect has been approved and the operator of
this project currently anticipates production from this project
to begin in the fourth quarter of 2006.
In June 2005, we increased our working interest in the LaSalle
project (East Breaks 513, 514 and 558) to 100% by acquiring
the remaining working interest owned by a third party for
$1.5 million. The blocks contain an undeveloped discovery,
as well as exploration potential. We have executed a
participation agreement with Kerr McGee to jointly develop the
LaSalle project and Kerr McGees nearby NW Nansen
exploitation project (East Breaks 602). Under the participation
agreement, Mariner owns a 33% working interest in the
NW Nansen project and a 50% working interest in the LaSalle
project. The LaSalle and NW Nansen projects are located
approximately 150 miles south of Galveston, Texas in water
depths of approximately 3,100 feet and 3,300 feet,
respectively. Mariner and Kerr McGee committed to drill four
wells, three on East Breaks 602 and one on East Breaks 558. The
four wells have been drilled and were successful. First
production is expected in 2008, with related completion and
facility capital being spent in 2006 and 2007. As of
December 31, 2005, we had not recorded proved reserves to
these projects.
At the King Kong field (Green Canyon blocks 472 and 473), a
two-well drilling program to exploit potential new reserve
additions has been executed. We drilled one successful
development well on block 473 in the first quarter of 2006,
and an unsuccessful exploration well on block 472 in the
second quarter of 2006. We own a 50% working interest in the
King Kong field in Green Canyon 472 and 473. The development
well on Green Canyon 473 has been completed and initial
production commenced in April 2006.
Gulf
of Mexico Shelf
Each of the following Gulf of Mexico shelf properties was
acquired by Mariner on March 2, 2006 as part of its merger
with Forest Energy Resources.
East Cameron 14. Forest acquired a 50% working
interest in this property through Forests acquisition of
Forcenergy Inc in 2000. Since March 2, 2006, Mariner has
operated the property and owns a 50% working
87
interest. This property is located in approximately 25 feet
of water, approximately 30 miles southeast of Cameron,
Louisiana.
Eugene Island 292. This property was installed
in 1967, with first production commencing in 1970. Since
March 2, 2006, Mariner has operated the property and owns a
45% working interest in this field. The property consists of a
hub for the complex including six platforms. The property is
located in approximately 195 feet of water, approximately
140 miles southeast of Cameron, Louisiana.
Eugene Island 53. The shallow rights to this
property were acquired in 1993 from Sandefer Offshore Operating.
Subsequently, the deep rights were acquired from Pennzoil in
1995 and 1997. Since March 2, 2006, Mariner has operated
the property and owns between 50% and 100% working interests in
various wells in the field. The property is located in
approximately 40 feet of water, approximately
111 miles southeast of Cameron, Louisiana.
High Island 116. This property was acquired in
1993 from Arco. In 2000 Forest purchased the remaining working
interests in this property and, since March 2, 2006,
Mariner has operated the property and owns a 100% working
interest as a result of our acquisition of the Forest Gulf of
Mexico operations. The property is located in approximately
45 feet of water, approximately 49 miles southwest of
Cameron, Louisiana. In October 2006, we announced that we made a
material conventional shelf discovery in the High Island 116
#5ST1 well, drilled to a total measured depth of 14,683 feet /
13,150 feet true vertical depth. The well encountered
approximately 540 feet of net true vertical depth pay in
thirteen sands. We anticipate completion and initial production
in the fourth quarter of 2006. We have a 100% working interest
and an approximate 72% net revenue interest in the well.
Ship Shoal 26. This property was acquired
through Forests acquisition of Forcenergy Inc in 2000.
Since March 2, 2006, Mariner has operated the property and
owns a 100% working interest in the property. The property is
located in approximately 10 feet of water, approximately
97 miles southwest of New Orleans, Louisiana.
South Marsh Island 18. This property was
acquired through Forests acquisition of Forcenergy Inc in
2000. Forest subsequently sold a 50% working interest in the
property to Union Oil of California (Unocal) in 2001. As part of
an acquisition of properties from Unocal in 2003, Forest
repurchased Unocals 50% working interest, and, since
March 2, 2006, Mariner has operated the property and holds
a 100% working interest. The property is located in
approximately 75 feet of water, approximately
101 miles southeast of Cameron, Louisiana.
South Pass 24 NCOC. This property was acquired
through Forests acquisition of Forcenergy Inc in 2000.
Forest acquired the remaining working interest (approximately
25%) from Pogo in 2004. Since March 2, 2006, Mariner has
operated the property and currently holds a 100% working
interest. The property is located approximately 82 miles
south of New Orleans, Louisiana in approximately 10 feet of
water.
Vermillion 14. A 50% working interest in this
property was acquired from Unocal in 2003. In 2004, Forest
acquired BPs 50% working interest and, since March 2,
2006, Mariner has operated the property and owns a 100% working
interest. The property is located in approximately 20 feet
of water, approximately 63 miles southeast of New Orleans,
Louisiana.
Vermillion 380. This property was acquired
through Forests acquisition of Forcenergy Inc in 2000.
Forest subsequently sold a 50% working interest to Unocal in
2001. As part of the Unocal acquisition in 2003, Forest
repurchased Unocals 50% working interest. Since
March 2, 2006, Mariner has operated the property and owns
working interests in the individual wells ranging from
approximately 55% to 100%. The property is located in
approximately 320 feet of water, approximately
135 miles southeast of Cameron, Louisiana.
West Cameron 110/SE/4 111. In August 2006,
Mariner Energy Resources, Inc. exercised a preferential right
with respect to the West Cameron 110 and the southeast quarter
of West Cameron 111, thereby increasing its working interest in
these properties to 100%, exclusive of retained interests in
depths below 15,000 feet. In addition, Mariner Energy, Inc.
became operator of the interests its subsidiary owns. A 37.5%
88
working interest was acquired through Forests acquisition
of Forcenergy Inc in 2000. The property is located in
approximately 45 feet of water, approximately 21 miles
south of Cameron, Louisiana.
West Cameron 111/112. This property consists
of the north half and southwest quarter of Block 111 and
all of Block 112, and was acquired through Forests
acquisition of Forcenergy Inc in 2000. Forest initially held a
100% working interest in the property and sold a portion of its
working interest in 2003 and, as a result, Mariner owns a 55%
working interest. Since March 2, 2006, Mariner has operated
the property. The property is located in approximately
40 feet of water, approximately 45 miles southeast of
Cameron, Louisiana.
West Cameron 205. This property was acquired
through Forests acquisition of Forcenergy Inc in 2000.
Since March 2, 2006, Mariner has operated the property and
owns a 100% working interest in the property, which is located
in approximately 50 feet of water, approximately
36 miles south of Cameron, Louisiana.
Other Projects and Activity. In connection
with the March 2005 Central Gulf of Mexico federal lease sale,
Mariner was awarded West Cameron 386 located in water depth of
approximately 85 feet. In connection with the August 2005
Western Gulf of Mexico lease sale, we were awarded one shelf
block (High Island A2) and four deepwater blocks (East Breaks
344, East Breaks 709, East Breaks 844 and East Breaks 843).
In May 2005, Mariner drilled the Capricorn discovery well, which
encountered over 100 net feet of pay in four zones. The
Capricorn project is located on High Island A341 approximately
115 miles south southwest of Cameron, Louisiana, in
approximately 240 feet of water. During 2006, the platform
and facilities were installed, and a successful appraisal well
was drilled. Production from two wells commenced in the third
quarter of 2006.
In late 2002, Mariner drilled a successful exploration well on
our Mississippi Canyon 66 (Ochre) prospect and commenced
production in the first quarter of 2004 via subsea tieback of
approximately 7 miles to the Taylor Mississippi Canyon 20
platform. In September 2004, Hurricane Ivan destroyed the Taylor
platform. We have entered into a production handling agreement
with the operator of the nearby Amberjack (MC109) host facility,
and production recommenced in the third quarter of 2006,
following completion of the operators repairs to the host
facility necessitated by damage inflicted by Hurricane Katrina.
In connection with the March 2006 Central Gulf of Mexico lease
sale, Mariner was the high bidder on ten blocks including two
deepwater blocks, at a potential aggregate cost of
$18 million to Mariner. We have been awarded nine blocks,
including the block on which we made our highest bid and the two
deepwater blocks (Mississippi Canyon 152 and 239). Our net cost
exposure for the nine blocks is approximately
$16.5 million. No lease was awarded on a tenth block on
which we also were the high bidder.
At the August 2006 Western Gulf of Mexico lease sale,
Mariner was the apparent high bidder on six blocks, including
High Island Blocks 233, A21, A126, A154, A155 and A480,
located in water depths ranging from 39 feet to
151 feet. We since have been awarded High Island Block A126
and await any further awards. Our potential cost exposure for
the approximately 25,000 net acres covered by the blocks is
approximately $4.4 million.
89
Estimated
Proved Reserves
The following table sets forth certain information with respect
to our estimated proved reserves by geographic area as of
December 31, 2005. Reserve volumes and values were
determined under the method prescribed by the SEC which requires
the application of period-end prices and costs held constant
throughout the projected reserve life. The reserve information
as of December 31, 2005 for Mariner is based on estimates
made in a reserve report prepared by Ryder Scott.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve Quantities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
PV10 Value(3)
|
|
|
Standardized
|
|
Geographic Area
|
|
(MMbbls)
|
|
|
(Bcf)
|
|
|
(Bcfe)
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
Measure
|
|
|
West Texas
|
|
|
16.7
|
|
|
|
105.5
|
|
|
|
205.5
|
|
|
$
|
333.7
|
|
|
$
|
173.4
|
|
|
$
|
507.1
|
|
|
|
|
|
Gulf of Mexico Deepwater(1)**
|
|
|
4.7
|
|
|
|
83.2
|
|
|
|
111.1
|
|
|
|
383.3
|
|
|
|
257.4
|
|
|
|
640.7
|
|
|
|
|
|
Gulf of Mexico Shelf(2)
|
|
|
0.3
|
|
|
|
19.0
|
|
|
|
21.0
|
|
|
|
132.6
|
|
|
|
1.4
|
|
|
|
134.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.7
|
|
|
|
207.7
|
|
|
|
337.6
|
|
|
$
|
849.6
|
|
|
$
|
432.2
|
|
|
$
|
1,281.8
|
|
|
$
|
906.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
9.6
|
|
|
|
110.0
|
|
|
|
167.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service). |
|
(2) |
|
Shelf refers to water depths less than 1,300 feet and
includes an insignificant amount of Gulf Coast onshore
properties. |
|
(3) |
|
Please see below for a definition of PV10 and a reconciliation
of PV10 to the standardized measure of discounted future net
cash flows. |
The following table sets forth certain information with respect
to our pro forma estimated proved reserves by geographic area as
of December 31, 2005. This information is presented on a
pro forma basis, giving effect to our merger with Forest Energy
Resources as though it had been consummated on December 31,
2005. We consummated the merger on March 2, 2006. The
reserve information as of December 31, 2005 for the Forest
Gulf of Mexico operations is based on estimates made by internal
staff engineers at Forest, which estimates were audited by Ryder
Scott. Accordingly, the pro forma reserve information presented
below includes both reserves that were estimated by Ryder Scott
and reserves that were estimated by internal staff engineers at
Forest and audited by Ryder Scott.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve Quantities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
PV10 Value(3)
|
|
|
Standardized
|
|
Geographic Area
|
|
(MMbbls)
|
|
|
(Bcf)
|
|
|
(Bcfe)
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions)
|
|
|
|
|
|
($ millions)
|
|
|
West Texas
|
|
|
16.7
|
|
|
|
105.5
|
|
|
|
205.5
|
|
|
$
|
333.7
|
|
|
$
|
173.4
|
|
|
$
|
507.1
|
|
|
|
|
|
Gulf of Mexico Deepwater(1)**
|
|
|
4.8
|
|
|
|
95.7
|
|
|
|
124.5
|
|
|
|
406.3
|
|
|
|
310.3
|
|
|
|
716.6
|
|
|
|
|
|
Gulf of Mexico Shelf(2)
|
|
|
12.7
|
|
|
|
237.6
|
|
|
|
313.7
|
|
|
|
1,283.4
|
|
|
|
544.7
|
|
|
|
1,828.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
34.2
|
|
|
|
438.8
|
|
|
|
643.7
|
|
|
$
|
2,023.4
|
|
|
$
|
1,028.4
|
|
|
$
|
3,051.8
|
|
|
$
|
2,201.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
18.4
|
|
|
|
252.1
|
|
|
|
362.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service). |
|
(2) |
|
Shelf refers to water depths less than 1,300 feet and
includes an insignificant amount of Gulf Coast onshore
properties. |
90
|
|
|
(3) |
|
Please see below for a definition of PV10 and a reconciliation
of PV10 to the standardized measure of discounted future net
cash flows. |
Uncertainties are inherent in estimating quantities of proved
reserves, including many factors beyond the control of Mariner.
Reserve engineering is a subjective process of estimating
subsurface accumulations of oil and gas that cannot be measured
in an exact manner, and the accuracy of any reserve estimate is
a function of the quality of available data and the
interpretation thereof. As a result, estimates by different
engineers often vary, sometimes significantly. In addition,
physical factors such as the results of drilling, testing, and
production subsequent to the date of an estimate, as well as
economic factors such as change in product prices, may require
revision of such estimates. Accordingly, oil and gas quantities
ultimately recovered may vary from reserve estimates.
PV10 is our estimated present value of future net revenues from
proved reserves before income taxes. PV10 may be considered a
non-GAAP financial measure under SEC regulations because it does
not include the effects of future income taxes, as is required
in computing the standardized measure of discounted future net
cash flows. We believe PV10 to be an important measure for
evaluating the relative significance of our natural gas and oil
properties and that PV10 is widely used by professional analysts
and investors in evaluating oil and gas companies. Because many
factors that are unique to each individual company affect the
amount of future income taxes to be paid, the use of a pre-tax
measure provides greater comparability of assets when evaluating
companies. We believe that most other companies in the oil and
gas industry calculate PV10 on the same basis. Management also
uses PV10 in evaluating acquisition candidates. PV10 is computed
on the same basis as the standardized measure of discounted
future net cash flows but without deducting income taxes. The
table below provides a reconciliation of PV10 (and, with respect
to 2005, pro forma PV10) to the standardized measure of
discounted future net cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma at
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
At December 31,
|
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In millions)
|
|
|
PV10
|
|
$
|
3,051.8
|
|
|
$
|
1,281.8
|
|
|
$
|
668.0
|
|
|
$
|
533.5
|
|
Future income taxes, discounted at
10%
|
|
|
850.1
|
|
|
|
375.2
|
|
|
|
173.6
|
|
|
|
115.3
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
2,201.7
|
|
|
$
|
906.6
|
|
|
$
|
494.4
|
|
|
$
|
418.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Therefore,
without reserve additions in excess of production through
successful exploration and development activities or
acquisitions, Mariners reserves and production will
decline. See Risk Factors and Note 11 to the
Mariner financial statements included elsewhere in this
prospectus for a discussion of the risks inherent in oil and
natural gas estimates and for certain additional information
concerning the proved reserves.
The weighted average prices of oil and natural gas at
December 31, 2005 used in the proved reserve and future net
revenues estimates above were calculated using NYMEX prices at
December 31, 2005, of $61.04 per bbl of oil and
$10.05 per MMBtu of gas, adjusted for our price
differentials but excluding the effects of hedging.
91
Production
The following table presents certain information with respect to
net oil and natural gas production attributable to our
properties, average sales price received and expenses per unit
of production during the periods indicated. The information for
the six months ended June 30, 2006 and year ended
December 31, 2005 also is presented on a pro forma basis,
giving effect to our merger with Forest Energy Resources as
though it had been consummated on January 1, 2005. We
consummated the merger on March 2, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Year
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
28.9
|
|
|
|
67.5
|
|
|
|
22.7
|
|
|
|
18.4
|
|
|
|
23.8
|
|
|
|
23.8
|
|
Oil (Mbbls)
|
|
|
1.8
|
|
|
|
4.6
|
|
|
|
1.5
|
|
|
|
1.8
|
|
|
|
2.3
|
|
|
|
1.6
|
|
Total natural gas equivalent (Bcfe)
|
|
|
39.7
|
|
|
|
94.9
|
|
|
|
31.8
|
|
|
|
29.1
|
|
|
|
37.6
|
|
|
|
33.4
|
|
Average daily natural gas
equivalent (MMcfe)
|
|
|
219.3
|
|
|
|
260.0
|
|
|
|
175.8
|
|
|
|
79.7
|
|
|
|
103.0
|
|
|
|
91.5
|
|
Average realized sales price
per unit (excluding the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
7.44
|
|
|
$
|
8.04
|
|
|
$
|
7.14
|
|
|
$
|
8.33
|
|
|
$
|
6.12
|
|
|
$
|
5.43
|
|
Oil ($/bbl)
|
|
|
59.97
|
|
|
|
48.86
|
|
|
|
61.20
|
|
|
|
51.66
|
|
|
|
38.52
|
|
|
|
26.85
|
|
Total natural gas equivalent
($/Mcfe)
|
|
|
8.13
|
|
|
|
8.07
|
|
|
|
8.02
|
|
|
|
8.43
|
|
|
|
6.23
|
|
|
|
5.15
|
|
Average realized sales price
per unit (including the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
7.32
|
|
|
$
|
6.40
|
|
|
$
|
7.00
|
|
|
$
|
6.66
|
|
|
$
|
5.80
|
|
|
$
|
4.40
|
|
Oil ($/bbl)
|
|
|
56.85
|
|
|
|
34.18
|
|
|
|
57.53
|
|
|
|
41.23
|
|
|
|
33.17
|
|
|
|
23.74
|
|
Total natural gas equivalent
($/Mcfe)
|
|
|
7.91
|
|
|
|
6.20
|
|
|
|
7.74
|
|
|
|
6.74
|
|
|
|
5.70
|
|
|
|
4.27
|
|
Expenses ($/Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.37
|
|
|
$
|
1.17
|
|
|
$
|
1.18
|
|
|
$
|
1.03
|
|
|
$
|
0.68
|
|
|
$
|
0.74
|
|
Transportation
|
|
|
0.06
|
|
|
|
0.06
|
|
|
|
0.07
|
|
|
|
0.08
|
|
|
|
0.08
|
|
|
|
0.19
|
|
General and administrative, net(1)
|
|
|
|
|
|
|
|
|
|
|
0.55
|
|
|
|
1.27
|
|
|
|
0.23
|
|
|
|
0.24
|
|
Depreciation, depletion and
amortization (excluding impairments)(2)
|
|
|
3.44
|
|
|
|
3.47
|
|
|
|
3.45
|
|
|
|
2.04
|
|
|
|
1.73
|
|
|
|
1.45
|
|
|
|
|
(1) |
|
Net of overhead reimbursements received from other working
interest owners and amounts capitalized under the full cost
accounting method. Includes non-cash stock compensation expense
of $7.9 million for the six months ended June 30, 2006
and $25.7 million in 2005. General and administrative
expenses, net of capitalized amounts, are not included in pro
forma 2005 because accounts of such costs were not historically
maintained for the Forest Gulf of Mexico operations as a
separate business unit. We believe the overhead costs associated
with the Forest Gulf of Mexico operations in 2006 will
approximate $6.4 million, net of capitalized amounts. |
|
(2) |
|
Pro forma depreciation, depletion and amortization gives effect
to the acquisition of the Forest Gulf of Mexico operations and a
preliminary estimate of their
step-up in
value basis the unit of production method under the full cost
method of accounting. |
92
Productive
Wells
The following table sets forth the number of productive oil and
gas wells in which we owned a working interest at
December 31, 2005 and December 31, 2004, and on a pro
forma basis at December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma at
|
|
|
Total Productive Wells at
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Oil
|
|
|
669
|
|
|
|
335.0
|
|
|
|
492
|
|
|
|
271.3
|
|
|
|
197
|
|
|
|
127.9
|
|
Gas
|
|
|
266
|
|
|
|
117.3
|
|
|
|
37
|
|
|
|
10.7
|
|
|
|
34
|
|
|
|
9.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
935
|
|
|
|
452.3
|
|
|
|
529
|
|
|
|
282.0
|
|
|
|
231
|
|
|
|
137.4
|
|
Acreage
The following table sets forth certain information with respect
to actual developed and undeveloped acreage as of June 30,
2006, and pro forma and actual developed and undeveloped acreage
as of December 31, 2005. The pro forma information gives
effect to our merger with Forest Energy Resources as though it
had been consummated on December 31, 2005. We consummated
the merger on March 2, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
June 30, 2006
|
|
|
at December 31, 2005
|
|
|
At December 31, 2005
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
|
Acres(1)
|
|
|
Acres(2)
|
|
|
Acres(1)
|
|
|
Acres(2)
|
|
|
Acres(1)
|
|
|
Acres(2)
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
West Texas
|
|
|
59,974
|
|
|
|
31,186
|
|
|
|
|
|
|
|
|
|
|
|
59,974
|
|
|
|
31,199
|
|
|
|
|
|
|
|
|
|
|
|
59,974
|
|
|
|
31,199
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico Deepwater(3)
|
|
|
97,740
|
|
|
|
38,906
|
|
|
|
345,600
|
|
|
|
232,756
|
|
|
|
90,720
|
|
|
|
36,035
|
|
|
|
332,528
|
|
|
|
205,285
|
|
|
|
79,200
|
|
|
|
30,275
|
|
|
|
259,200
|
|
|
|
154,996
|
|
Gulf of Mexico Shelf(4)
|
|
|
802,943
|
|
|
|
378,177
|
|
|
|
384,789
|
|
|
|
244,807
|
|
|
|
1,007,882
|
|
|
|
399,184
|
|
|
|
399,792
|
|
|
|
251,915
|
|
|
|
136,062
|
|
|
|
40,435
|
|
|
|
137,128
|
|
|
|
82,758
|
|
Other Onshore
|
|
|
1,311
|
|
|
|
344
|
|
|
|
854
|
|
|
|
242
|
|
|
|
3,392
|
|
|
|
744
|
|
|
|
856
|
|
|
|
243
|
|
|
|
3,392
|
|
|
|
744
|
|
|
|
856
|
|
|
|
243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
961,968
|
|
|
|
448,613
|
|
|
|
731,243
|
|
|
|
477,805
|
|
|
|
1,161,968
|
|
|
|
467,162
|
|
|
|
733,176
|
|
|
|
457,443
|
|
|
|
278,628
|
|
|
|
102,653
|
|
|
|
397,184
|
|
|
|
237,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Developed acres are acres spaced or assigned to productive wells. |
|
(2) |
|
Undeveloped acres are acres on which wells have not been drilled
or completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of
whether such acreage contains proved reserves. |
|
(3) |
|
Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designated for royalty
purposes by the U.S. Minerals Management Service). |
|
(4) |
|
Shelf refers to water depths less than 1,300 feet. |
The following table sets forth Mariners offshore
undeveloped acreage as of December 31, 2005 that is subject
to expiration during the three years ended December 31,
2008. The amount of onshore undeveloped acreage subject to
expiration is not material.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acreage
|
|
|
|
Subject to Expiration in the Year Ended December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Oil
|
|
|
46,080
|
|
|
|
12,988
|
|
|
|
28,800
|
|
|
|
9,360
|
|
|
|
51,840
|
|
|
|
30,240
|
|
Gas
|
|
|
10,760
|
|
|
|
6,260
|
|
|
|
46,000
|
|
|
|
31,183
|
|
|
|
25,760
|
|
|
|
16,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
56,840
|
|
|
|
19,248
|
|
|
|
74,800
|
|
|
|
40,543
|
|
|
|
77,600
|
|
|
|
46,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93
Drilling
Activity
Certain information with regard to our drilling activity during
the six months ended June 30, 2006 and the years ended
December 31, 2005, 2004 and 2003 is set forth below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
10
|
|
|
|
4.90
|
|
|
|
3
|
|
|
|
1.13
|
|
|
|
7
|
|
|
|
3.34
|
|
|
|
6
|
|
|
|
2.03
|
|
Dry
|
|
|
5
|
|
|
|
2.50
|
|
|
|
7
|
|
|
|
2.44
|
|
|
|
7
|
|
|
|
2.65
|
|
|
|
6
|
|
|
|
2.35
|
|
Total
|
|
|
15
|
|
|
|
7.40
|
|
|
|
10
|
|
|
|
3.57
|
|
|
|
14
|
|
|
|
5.99
|
|
|
|
12
|
|
|
|
4.38
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
83
|
|
|
|
41.47
|
|
|
|
93
|
|
|
|
54.20
|
|
|
|
56
|
|
|
|
34.84
|
|
|
|
45
|
|
|
|
30.07
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
0.68
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
83
|
|
|
|
41.47
|
|
|
|
93
|
|
|
|
54.20
|
|
|
|
57
|
|
|
|
35.52
|
|
|
|
45
|
|
|
|
30.07
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
93
|
|
|
|
46.37
|
|
|
|
96
|
|
|
|
55.33
|
|
|
|
63
|
|
|
|
38.18
|
|
|
|
51
|
|
|
|
32.10
|
|
Dry
|
|
|
5
|
|
|
|
2.50
|
|
|
|
7
|
|
|
|
2.44
|
|
|
|
8
|
|
|
|
3.33
|
|
|
|
6
|
|
|
|
2.35
|
|
Total
|
|
|
98
|
|
|
|
48.87
|
|
|
|
103
|
|
|
|
57.77
|
|
|
|
71
|
|
|
|
41.51
|
|
|
|
57
|
|
|
|
34.45
|
|
As of June 30, 2006, we were in the process of drilling six
gross (2.315 net) wells in the Gulf of Mexico and five gross
(approximately 2.4 net) wells in West Texas.
Property
Dispositions
When appropriate, we consider the sale of discoveries that are
not yet producing or have recently begun producing when we
believe we can obtain acceptable returns on our investment
without holding the investment through depletion. Such sales
enable us to maintain and redeploy the proceeds to activities
that we believe have a higher potential financial return. No
property dispositions of producing properties were made during
the three years ended December 31, 2005. We sold working
interests totaling 50% in each of our non-producing deepwater
Falcon and Harrier projects in two separate sales for
$48.8 million in 2002 and $121.6 million in 2003.
94
Marketing
and Customers
We market substantially all of the oil and natural gas
production from the properties we operate as well as the
properties operated by others where our interest is significant.
The majority of our natural gas, oil and condensate production
is sold to a variety of purchasers under short-term (less than
12 months) contracts at market-based prices. The following
table lists customers accounting for more than 10% of our total
revenues for the year indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Total
|
|
|
|
Revenues for
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
Customer
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Sempra
|
|
|
|
|
|
|
*
|
|
|
|
34
|
%
|
Bridgeline Gas Distributing
Company(1)
|
|
|
15
|
%
|
|
|
27
|
%
|
|
|
19
|
%
|
Trammo Petroleum Inc.
|
|
|
*
|
|
|
|
9
|
%
|
|
|
14
|
%
|
Duke Energy
|
|
|
*
|
|
|
|
*
|
|
|
|
6
|
%
|
Genesis Crude Oil LP
|
|
|
|
|
|
|
*
|
|
|
|
4
|
%
|
Chevron Texaco and affiliates(1)
|
|
|
24
|
%
|
|
|
18
|
%
|
|
|
|
|
BP Energy
|
|
|
*
|
|
|
|
12
|
%
|
|
|
|
|
Plains Marketing LP
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Less than 1% |
|
(1) |
|
Bridgeline Gas Distributing Company is an affiliate of
ChevronTexaco. |
Title to
Properties
Substantially all of our properties currently are subject to
liens securing our credit facility and obligations under hedging
arrangements with members of our bank group. In addition, our
properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and
other typical burdens and encumbrances. We do not believe that
any of these burdens or encumbrances materially interferes with
the use of such properties in the operation of our business. Our
properties may also be subject to obligations or duties under
applicable laws, ordinances, rules, regulations and orders of
governmental authorities.
We believe that we have satisfactory title to or rights in all
of our producing properties. As is customary in the oil and
natural gas industry, minimal investigation of title is made at
the time of acquisition of undeveloped properties. Title
investigation is made usually only before commencement of
drilling operations. We believe that title issues generally are
not as likely to arise with respect to offshore oil and gas
properties as with respect to onshore properties.
Competition
We believe that our leasehold acreage, exploration, drilling and
production capabilities,
large 3-D
seismic database and technical and operational experience
generally enable us to compete effectively. However, our primary
competitors include major integrated oil and natural gas
companies and major independent oil and natural gas companies.
Many of our larger competitors possess and employ financial and
personnel resources substantially greater than those available
to us. Such companies may be able to pay more for productive oil
and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of
properties and prospects than our financial or personnel
resources permit. Our ability to acquire additional prospects
and discover reserves in the future is dependent upon our
ability to evaluate and select suitable properties and
consummate transactions in a highly competitive environment. In
addition, there is substantial competition for capital available
for investment in the oil and natural gas industry. Larger
competitors may be better able to withstand sustained periods of
unsuccessful drilling and absorb the burden
95
of changes in laws and regulations more easily than we can,
which would adversely affect our competitive position.
Royalty
Relief
The Outer Continental Shelf Deep Water Royalty Relief Act, or
RRA, signed into law on November 28, 1995, provides that
all tracts in the Gulf of Mexico west of 87 degrees, 30 minutes
West longitude in water more than 200 meters deep offered for
bid within five years after the RRA was enacted will be relieved
from normal federal royalties as follows:
|
|
|
|
|
Water Depth
|
|
Royalty Relief
|
|
200-400 meters
|
|
|
no royalty payable on the first 105 Bcfe produced
|
|
400-800 meters
|
|
|
no royalty payable on the first 315 Bcfe produced
|
|
800 meters or deeper
|
|
|
no royalty payable on the first 525 Bcfe produced
|
|
Leases offered for bid within five years after the RRA was
enacted are referred to as post-Act leases. The RRA
also allows mineral interest owners the opportunity to apply for
discretionary royalty relief for new production on leases
acquired before the RRA was enacted, or pre-Act leases, and on
leases acquired after November 28, 2000, or post-2000
leases. If the MMS determines that new production under a
pre-Act lease or post-2000 lease would not be economical without
royalty relief, then the MMS may relieve a portion of the
royalty to make the project economical.
In addition to granting discretionary royalty relief, the MMS
has elected to include automatic royalty relief provisions in
many post-2000 leases, even though the RRA no longer applies.
For each post-2000 lease sale that has occurred to date, the MMS
has specified the water depth categories and royalty suspension
volumes applicable to production from leases issued in the sale.
In 2004, the MMS adopted additional royalty relief incentives
for production of natural gas from reservoirs located deep under
shallow waters of the Gulf of Mexico. These incentives apply to
gas produced in water depths of less than 200 meters and from
deep gas accumulations located at water depths of greater than
15,000 feet. Drilling of qualified wells must have started
on or after March 26, 2003, and production must begin prior
to January 26, 2009.
The impact of royalty relief can be significant. The normal
royalty due for leases in water depths of 400 meters or less is
16.7% of production, and the normal royalty for leases in water
depths greater than 400 meters is 12.5% of production. Royalty
relief can substantially improve the economics of projects
located in deepwater or in shallow water and involving deep gas.
Many of our leases from the MMS contain language suspending
royalty relief if commodity prices exceed predetermined
threshold levels for a given calendar year. As a result, royalty
relief for a lease in a particular calendar year may be
contingent upon average commodity prices staying below the
threshold price specified for that year. In 2000, 2001, 2003,
2004 and 2005, natural gas prices exceeded the applicable price
thresholds for a number of our projects, and we have been
required to pay royalties for natural gas produced in those
years. However, we have contested the authority of the MMS to
include price thresholds in two of our post-Act leases, Black
Widow and Garden Banks 367. We believe that post-Act leases are
entitled to automatic royalty relief under the RRA regardless of
commodity prices, and have pursued administrative and judicial
remedies in this dispute with the MMS. For more information
concerning the contested royalty payments and the MMSs
demands, see Legal Proceedings below.
Regulation
Our operations are subject to extensive and continually changing
regulation affecting the oil and natural gas industry. Many
departments and agencies, both federal and state, are authorized
by statute to issue, and have issued, rules and regulations
binding on the oil and natural gas industry and its individual
participants. The failure to comply with such rules and
regulations can result in substantial penalties. The regulatory
burden on the oil and natural gas industry increases our cost of
doing business and, consequently, affects our
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profitability. We do not believe that we are affected in a
significantly different manner by these regulations than are our
competitors.
Transportation
and Sale of Natural Gas
Historically, the transportation and sale for resale of natural
gas in interstate commerce have been regulated pursuant to the
Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and
the regulations promulgated thereunder by the Federal Energy
Regulatory Commission, or FERC. In the past, the federal
government has regulated the prices at which natural gas could
be sold. Deregulation of natural gas sales by producers began
with the enactment of the Natural Gas Policy Act of 1978. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act,
which removed all remaining Natural Gas Act of 1938 and Natural
Gas Policy Act of 1978 price and non-price controls affecting
producer sales of natural gas effective January 1, 1993.
Congress could, however, re-enact price controls in the future.
The FERC regulates interstate natural gas pipeline
transportation rates and service conditions, which affect the
marketing of gas produced by us and the revenues received by us
for sales of such natural gas. The FERC requires interstate
pipelines to provide open-access transportation on a
non-discriminatory basis for all natural gas shippers. The FERC
frequently reviews and modifies its regulations regarding the
transportation of natural gas with the stated goal of fostering
competition within all phases of the natural gas industry. In
addition, with respect to production onshore or in state waters,
the intra-state transportation of natural gas would be subject
to state regulatory jurisdiction as well.
In August, 2005, Congress enacted the Energy Policy Act of 2005,
or EP Act 2005. Among other matters, EP Act 2005 amends the
Natural Gas Act, or NGA, to make it unlawful for any
entity, including otherwise non-jurisdictional producers
such as Mariner, to use any deceptive or manipulative device or
contrivance in connection with the purchase or sale of natural
gas or the purchase or sale of transportation services subject
to regulation by the FERC, in contravention of rules prescribed
by the FERC. On January 19, 2006, the FERC issued
regulations implementing this provision. The regulations make it
unlawful in connection with the purchase or sale of natural gas
subject to the jurisdiction of the FERC, or the purchase or sale
of transportation services subject to the jurisdiction of the
FERC, for any entity, directly or indirectly, to use or employ
any device, scheme or artifice to defraud; to make any untrue
statement of material fact or omit to make any such statement
necessary to make the statements made not misleading; or to
engage in any act or practice that operates as a fraud or deceit
upon any person. EP Act 2005 also gives the FERC authority to
impose civil penalties for violations of the NGA up to
$1,000,000 per day per violation. The new anti-manipulation
rule does not apply to activities that relate only to intrastate
or other non-jurisdictional sales or gathering, but does apply
to activities of otherwise non-jurisdictional entities to the
extent the activities are conducted in connection
with gas sales, purchases or transportation subject to
FERC jurisdiction. It therefore reflects a significant expansion
of the FERCs enforcement authority. We do not anticipate
we will be affected any differently than other producers of
natural gas.
Additional proposals and proceedings that might affect the
natural gas industry are considered from time to time by
Congress, the FERC, state regulatory bodies and the courts. We
cannot predict when or if any such proposals might become
effective or their effect, if any, on our operations. The
natural gas industry historically has been closely regulated;
thus, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue
indefinitely into the future.
Regulation
of Production
The production of oil and natural gas is subject to regulation
under a wide range of state and federal statutes, rules, orders
and regulations. State and federal statutes and regulations
require permits for drilling operations, drilling bonds, and
reports concerning operations. Texas and Louisiana, the states
in which we own and operate properties, have regulations
governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and
natural gas wells, the spacing of wells, and the plugging and
abandonment of wells and removal of related production
equipment. Texas and Louisiana also restrict production to the
market demand for oil and natural gas and several states have
indicated interests in revising applicable regulations. These
regulations
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can limit the amount of oil and natural gas we can produce from
our wells, limit the number of wells, or limit the locations at
which we can conduct drilling operations. Moreover, each state
generally imposes a production or severance tax with respect to
production and sale of crude oil, natural gas and gas liquids
within its jurisdiction.
Most of our offshore operations are conducted on federal leases
that are administered by the MMS. Such leases require compliance
with detailed MMS regulations and orders pursuant to the Outer
Continental Shelf Lands Act that are subject to interpretation
and change by the MMS. Among other things, we are required to
obtain prior MMS approval for our exploration plans and
development and production plans at each lease. MMS regulations
also impose construction requirements for production facilities
located on federal offshore leases, as well as detailed
technical requirements for plugging and abandonment of wells,
and removal of platforms and other production facilities on such
leases. The MMS requires lessees to post surety bonds, or
provide other acceptable financial assurances, to ensure all
obligations are satisfied on federal offshore leases. The cost
of these surety bonds or other financial assurances can be
substantial, and there is no assurance that bonds or other
financial assurances can be obtained in all cases. We are
currently in compliance with all MMS financial assurance
requirements. Under certain circumstances, the MMS is authorized
to suspend or terminate operations on federal offshore leases.
Any suspension or termination of operations on our offshore
leases could have an adverse effect on our financial condition
and results of operations.
In 2000, the MMS issued a final rule that governs the
calculation of royalties and the valuation of crude oil produced
from federal leases. That rule amended the way that the MMS
values crude oil produced from federal leases for determining
royalties by eliminating posted prices as a measure of value and
relying instead on arms-length sales prices and spot
market prices as indicators of value. On May 5, 2004, the
MMS issued a final rule that changed certain components of its
valuation procedures for the calculation of royalties owed for
crude oil sales. The changes include changing the valuation
basis for transactions not at arms-length from spot to
NYMEX prices adjusted for locality and quality differentials,
and clarifying the treatment of transactions under a joint
operating agreement. We believe that the changes will not have a
material impact on our financial condition, liquidity or results
of operations.
Environmental
Regulations
Our operations are subject to numerous stringent and complex
laws and regulations at the federal, state and local levels
governing the discharge of materials into the environment or
otherwise relating to human health and environmental protection.
These laws and regulations may, among other things:
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require acquisition of a permit before drilling commences;
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restrict the types, quantities and concentrations of various
materials that can be released into the environment in
connection with drilling and production activities; and
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limit or prohibit construction or drilling activities in certain
ecologically sensitive and other protected areas.
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Failure to comply with these laws and regulations or to obtain
or comply with permits may result in the assessment of
administrative, civil and criminal penalties, imposition of
remedial requirements and the imposition of injunctions to force
future compliance. Offshore drilling in some areas has been
opposed by environmental groups and, in some areas, has been
restricted. Our business and prospects could be adversely
affected to the extent laws are enacted or other governmental
action is taken that prohibits or restricts our exploration and
production activities or imposes environmental protection
requirements that result in increased costs to us or the oil and
natural gas industry in general.
Spills and Releases. The Comprehensive
Environmental Response, Compensation, and Liability Act, or
CERCLA, and analogous state laws, impose joint and several
liability, without regard to fault or the legality of the
original act, on certain classes of persons that contributed to
the release of a hazardous substance into the
environment. These persons include the owner and
operator of the site where the release occurred,
past owners and operators of the site, and companies that
disposed or arranged for the disposal of the hazardous
substances found at the site. Responsible parties under CERCLA
may be liable for the costs of
98
cleaning up hazardous substances that have been released into
the environment and for damages to natural resources.
Additionally, it is not uncommon for neighboring landowners and
other third parties to file tort claims for personal injury and
property damage allegedly caused by the release of hazardous
substances into the environment. In the course of our ordinary
operations, we may generate waste that may fall within
CERCLAs definition of a hazardous substance.
We currently own, lease or operate, and have in the past owned,
leased or operated, numerous properties that for many years have
been used for the exploration and production of oil and gas.
Many of these properties have been operated by third parties
whose actions with respect to the treatment and disposal or
release of hydrocarbons or other wastes were not under our
control. It is possible that hydrocarbons or other wastes may
have been disposed of or released on or under such properties,
or on or under other locations where such wastes may have been
taken for disposal. These properties and wastes disposed thereon
may be subject to CERCLA and analogous state laws. Under such
laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by
prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial
plugging operations to prevent future contamination, or to pay
the costs of such remedial measures. Although we believe we have
utilized operating and disposal practices that are standard in
the industry, during the course of operations hydrocarbons and
other wastes may have been released on some of the properties we
own, lease or operate. We are not presently aware of any pending
clean-up
obligations that could have a material impact on our operations
or financial condition.
The Oil Pollution Act. The OPA and regulations
thereunder impose strict, joint and several liability on
responsible parties for damages, including natural
resource damages, resulting from oil spills into or upon
navigable waters, adjoining shorelines or in the exclusive
economic zone of the U.S. A responsible party
includes the owner or operator of an onshore facility and the
lessee or permittee of the area in which an offshore facility is
located. The OPA establishes a liability limit for onshore
facilities of $350 million, while the liability limit for
offshore facilities is equal to all removal costs plus up to
$75 million in other damages. These liability limits may
not apply if a spill is caused by a partys gross
negligence or willful misconduct, the spill resulted from
violation of a federal safety, construction or operating
regulation, or if a party fails to report a spill or to
cooperate fully in a clean-up.
The OPA also requires the lessee or permittee of an offshore
area in which a covered offshore facility is located to provide
financial assurance in the amount of $35 million to cover
liabilities related to an oil spill. The amount of financial
assurance required under the OPA may be increased up to
$150 million depending on the risk represented by the
quantity or quality of oil that is handled by a facility. The
failure to comply with the OPAs requirements may subject a
responsible party to civil, criminal, or administrative
enforcement actions. We are not aware of any action or event
that would subject us to liability under the OPA, and we believe
that compliance with the OPAs financial assurance and
other operating requirements will not have a material impact on
our operations or financial condition.
Water Discharges. The Federal Water Pollution
Control Act of 1972, also known as the Clean Water Act, imposes
restrictions and controls on the discharge of produced waters
and other oil and gas pollutants into navigable waters. These
controls have become more stringent over the years, and it is
possible that additional restrictions may be imposed in the
future. Permits must be obtained to discharge pollutants into
state and federal waters. Certain state regulations and the
general permits issued under the Federal National Pollutant
Discharge Elimination System, or NPDES, program prohibit the
discharge of produced waters and sand, drilling fluids, drill
cuttings and certain other substances related to the oil and gas
industry into certain coastal and offshore water. The Clean
Water Act provides for civil, criminal and administrative
penalties for unauthorized discharges of oil and other
pollutants, and imposes liability on parties responsible for
those discharges for the costs of cleaning up any environmental
damage caused by the release and for natural resource damages
resulting from the release. Comparable state statutes impose
liabilities and authorize penalties in the case of an
unauthorized discharge of petroleum or its derivatives, or other
pollutants, into state waters.
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In furtherance of the Clean Water Act, the EPA promulgated the
Spill Prevention, Control, and Countermeasure, or SPCC,
regulations, which require facilities that possess certain
threshold quantities of oil that could impact navigable waters
or adjoining shorelines to prepare SPCC plans and meet specified
construction and operating standards. The SPCC regulations were
revised in 2002 and required the amendment of SPCC plans before
February 18, 2006, if necessary, and requires compliance
with the implementation of such amended plans by August 18,
2006 (on February 17, 2006, this compliance deadline was
extended until October 31, 2007). We may be required to
prepare SPCC plans for some of our facilities where a spill or
release of oil could reach or impact jurisdictional waters of
the U.S.
Air Emissions. The Federal Clean Air Act, and
associated state laws and regulations, restrict the emission of
air pollutants from many sources, including oil and natural gas
operations. New facilities may be required to obtain permits
before operations can commence, and existing facilities may be
required to obtain additional permits and incur capital costs in
order to remain in compliance. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties
for non-compliance with air permits or other requirements of the
Clean Air Act and associated state laws and regulations. We
believe that compliance with the Clean Air Act and analogous
state laws and regulations will not have a material impact on
our operations or financial condition.
Waste Handling. The Resource Conservation and
Recovery Act, or RCRA, and analogous state and local laws and
regulations govern the management of wastes, including the
treatment, storage and disposal of hazardous wastes. RCRA
imposes stringent operating requirements, and liability for
failure to meet such requirements, on a person who is either a
generator or transporter of hazardous
waste or an owner or operator of a
hazardous waste treatment, storage or disposal facility. RCRA
specifically excludes from the definition of hazardous waste
drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil
and natural gas. A similar exemption is contained in many of the
state counterparts to RCRA. As a result, we are not required to
comply with a substantial portion of RCRAs requirements
because our operations generate minimal quantities of hazardous
wastes. However, these wastes may be regulated by EPA or state
agencies as solid waste. In addition, ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes,
and waste compressor oils, may be regulated under RCRA as
hazardous waste. We do not believe the current costs of managing
our wastes, as they are presently classified, to be significant.
However, any repeal or modification of the oil and natural gas
exploration and production exemption, or modifications of
similar exemptions in analogous state statutes, would increase
the volume of hazardous waste we are required to manage and
dispose of and would cause us, as well as our competitors, to
incur increased operating expenses.
Employees
As of September 30, 2006, we had 214 full-time
employees. Our employees are not represented by any labor
unions. We consider relations with our employees to be
satisfactory. We have never experienced a work stoppage or
strike.
Legal
Proceedings
Each of Mariner and its subsidiary, Mariner Energy Resources,
Inc., owns numerous properties in the Gulf of Mexico. Certain of
these properties were leased from the MMS subject to the RRA.
The RRA relieved the obligation to pay royalties on certain
leases until a designated volume is produced. Two of these
leases held by Mariner and one held by its subsidiary contained
language that limited royalty relief if commodity prices
exceeded predetermined levels. Since 2000, commodity prices have
exceeded the predetermined levels, except in 2002. Mariner and
its subsidiary believe the MMS did not have the authority to set
pricing limits in these leases and have withheld payment of
royalties on the leases while disputing the MMS authority
in two pending proceedings. Mariner has recorded a liability for
100% of the exposure on its two leases, which at June 30,
2006 was $18.8 million. In April 2005, the MMS denied
Mariners administrative appeal of the MMS April 2001
order asserting royalties were due because price limits had been
exceeded. In October 2005, Mariner filed suit in the
U.S. District Court for the Southern District of Texas
seeking judicial review of the dismissal. Upon motion of the
MMS, Mariners lawsuit was dismissed on procedural grounds.
In August 2006,
100
Mariner filed an appeal of such dismissal. Mariner had also
filed an administrative appeal of a December 2005 order of the
MMS demanding royalties for calendar year 2004 under the same
leases at issue in the April 2001 MMS order. However, the
MMS withdrew such order, rendering the appeal moot. Thereafter,
in May 2006, the MMS issued an order asserting price limits were
exceeded in calendar years 2001, 2003 and 2004 and, accordingly,
that royalties were due under such leases on oil and gas
produced in those years. Mariner has filed and is pursuing an
administrative appeal of that order.
The potential liability of Mariner Energy Resources, Inc. under
its lease subject to the RRA containing such commodity price
threshold language is approximately $1.8 million as of
June 30, 2006. This potential liability relates to
production from the lease commencing July 1, 2005, the
effective date of Mariners acquisition of Mariner Energy
Resources, Inc. A reserve for this possible liability will be
made when deemed appropriate. The MMS has not yet made demand
for non-payment of royalties alleged to be due for calendar
years subsequent to 2004 on the basis of price thresholds being
exceeded.
In the ordinary course of business, we are a claimant
and/or a
defendant in various legal proceedings, including proceedings as
to which we have insurance coverage and those that may involve
the filing of liens against us or our assets. We do not consider
our exposure in these proceedings, individually or in the
aggregate, to be material.
Insurance
Matters
In September 2004, we incurred damage from Hurricane Ivan that
affected our Mississippi Canyon 66 (Ochre) and Mississippi
Canyon 357 fields. Production from Ochre was shut-in until
September 2006, when repairs to a host platform were completed
and production recommenced at about the same net rate of
approximately 6.5 MMcfe per day as it was prior to
Hurricane Ivan. Production from Mississippi Canyon 357 was
shut-in until March 2005, when necessary repairs were completed
and production recommenced. It subsequently has been shut-in
since Hurricane Katrina, with production expected to recommence
in the fourth quarter of 2006 after completion of host platform
repairs. We expect to be reimbursed for costs expended in excess
of our annual deductible of $1.25 million plus a single
occurrence deductible of $.375 million in effect for the
insurance period ended September 30, 2004. We recovered
approximately $2.0 million in insurance proceeds in the
second quarter of 2006.
In 2005, our operations were adversely affected by one of the
most active and severe hurricane seasons in recorded history,
resulting in shut-in production and startup delays. We estimate
that as of September 30, 2006, approximately 12 MMcfe
per day of production remained shut-in and approximately
33 MMcfe per day of production had recommenced since
June 30, 2006. The four deepwater projects that experienced
startup delays have recommenced production. As a result of
ongoing repairs to pipelines, facilities, terminals and host
facilities, we expect most of the remaining shut-in production
to recommence by the end of 2006 and the balance in 2007, except
that an immaterial amount of production is not expected to
recommence. Actual commencement or recommencement of deferred or
shut-in production will vary based on circumstances beyond our
control, including the timing of repairs to both onshore and
offshore platforms, pipelines and facilities, the actions of
operators on our fields, availability of service equipment, and
weather.
We estimate the costs to repair damage caused by Hurricanes
Katrina and Rita to our platforms and facilities will be
approximately $80 million. However, until we are able to
complete all the repair work this estimate is subject to
significant variance. For the insurance period covering the 2005
hurricane activity, we carried a $3 million annual
deductible and a $0.5 million single occurrence deductible
for the Mariner assets. Insurance covering the Forest Gulf of
Mexico properties carried a $5 million deductible for each
occurrence. Until the repairs are completed and we submit costs
to our insurance underwriters for review, the full extent of our
insurance recoveries and the resulting net cost to us for
Hurricanes Katrina and Rita will be unknown. However, we expect
the total costs not covered by the combined insurance policies
to be less than $15 million.
Effective March 2, 2006, Mariner has been accepted as a
member of OIL Insurance, Ltd., an industry insurance
cooperative, through which all of Mariners assets are
insured. The coverage contains a $5 million annual
per-occurrence deductible for the combined assets and a
$250 million per-occurrence loss limit. However, if a
single event causes losses to OIL insured assets in excess of
$500 million, amounts covered for
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such losses will be reduced on a pro rata basis among OIL
members. We maintained our commercially underwritten insurance
coverage for the premerger Mariner assets, which coverage
expired on September 30, 2006. This coverage contained a
$3 million annual deductible and a $500,000 occurrence
deductible, $150 million of aggregate loss limits, and
limited business interruption coverage. While the coverage was
in effect, it was primary to the OIL coverage for the pre-merger
Mariner assets. We have acquired additional windstorm/physical
damage insurance covering all of Mariners assets to
supplement the existing OIL coverage. The coverage provides up
to $31 million of annual loss coverage (with no additional
deductible) if recoveries from OIL for insured losses are
reduced by the OIL overall loss limit (i.e., if losses to OIL
insured assets from a single event exceed $500 million). We
also have acquired additional limited business interruption
insurance on most of our deepwater producing fields which
becomes effective 60 days after a field is shut-in due to a
covered event. The coverage varies by field and is limited to a
maximum recovery resulting from windstorm damage of
approximately $43 million (assuming all covered fields are
shut-in for the full insurance term of 365 days).
Enron
Related Matters
In 1996, JEDI, an indirect wholly owned subsidiary of Enron
Corp., acquired approximately 96% of Mariner Energy LLC, which
at the time of acquisition indirectly owned 100% of Mariner
Energy, Inc. After JEDI acquired us, we continued our prior
business as an independent oil and natural gas exploration,
development and production company. In 2001, Enron Corp. and
certain of its subsidiaries (excluding JEDI) became debtors in
Chapter 11 bankruptcy proceedings. Mariner Energy, Inc. was
not one of the debtors in those proceedings. While the
bankruptcy proceedings were ongoing, we continued to operate our
business as an indirect subsidiary of JEDI. We remained an
indirect subsidiary of JEDI until March of 2004 when our former
indirect parent company, Mariner Energy LLC, merged with an
affiliate of the private equity funds Carlyle/Riverstone Global
Energy and Power Fund II, L.P. and ACON Investments LLC. In
the merger, all the shares of common stock in Mariner Energy LLC
were converted into the right to receive cash and certain other
consideration. As a result, since March 2004, JEDI has not owned
any direct or indirect interest in Mariner, and we have not had
any affiliation with JEDI or Enron Corp. Also in connection with
the merger, warrants to purchase common stock of Mariner Energy
LLC that were held by another Enron Corp. affiliate were
exercised and the holders received their pro rata portion of the
merger consideration, and a term loan owed by Mariner Energy LLC
to the same Enron Corp. affiliate was repaid in full.
Prior to the merger, we filed two proofs of claim in the Enron
Corp. bankruptcy proceedings. These claims, aggregating
$10.7 million, were for unpaid amounts owed to us by Enron
Corp. subsidiaries under the terms of various physical commodity
contracts and hedging contracts entered into prior to the Enron
Corp. bankruptcy filing. We assigned these claims to JEDI as
part of the merger consideration payable to JEDI under the terms
of the merger agreement. Thus, as of this date, we have no
claims pending in the Enron Corp. bankruptcy proceedings.
As part of the merger consideration payable to JEDI, we also
issued a term promissory note to JEDI in the amount of
$10 million. The note bore interest, paid in kind, at a
rate of 10% per annum until March 2, 2005, and
12% per annum thereafter unless paid in cash in which event
the rate remained at 10% per annum. The JEDI promissory
note was secured by a lien on three of our properties located in
the Outer Continental Shelf of the Gulf of Mexico. We used a
portion of proceeds from the common stock we sold in our March
2005 private equity placement to repay $6 million of the
JEDI Note. The note matured on March 2, 2006 and was repaid
in full.
Under the merger agreement, JEDI and the other former
stockholders of our parent company were entitled to receive on
or before February 28, 2005, additional contingent merger
consideration based upon the results of a five-well drilling
program. In September 2004, we prepaid, with a 10% prepayment
discount, approximately $161,000 as the additional contingent
merger consideration due with respect to the program.
102
MANAGEMENT
Directors
and Executive Officers
The Board of Directors of Mariner is composed of seven directors.
The following table sets forth the names, ages (as of
September 30, 2006) and titles of the individuals who
are the directors and executive officers of Mariner. All
directors are elected for terms in accordance with their class,
as described in Board of Directors
below. All executive officers hold office until their successors
are elected and qualified. There are no family relationships
among any of our directors or executive officers.
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Name
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Age
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Position with Company
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Scott D. Josey
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49
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Chairman of the Board, Chief
Executive Officer and President
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Dalton F. Polasek
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54
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Chief Operating Officer
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Rick G. Lester
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54
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Vice President, Chief Financial
Officer and Treasurer
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Jesus G. Melendrez
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47
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Senior Vice President
Corporate Development
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Mike C. van den Bold
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43
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Senior Vice President and Chief
Exploration Officer
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Teresa G. Bushman
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57
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Senior Vice President, General
Counsel and Secretary
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Judd A. Hansen
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50
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Senior Vice President
Shelf and Onshore
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Cory L. Loegering
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51
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Vice President
Deepwater
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Richard A. Molohon
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51
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Vice President
Reservoir Engineering
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Bernard Aronson
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60
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Director
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Alan R. Crain, Jr.
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55
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Director
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Jonathan Ginns
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42
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Director
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John F. Greene
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66
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Director
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H. Clayton Peterson
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61
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Director
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John L. Schwager
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58
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Director
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Scott D. Josey Mr. Josey has served as
Chairman of the Board since August 2001. Mr. Josey was
appointed Chief Executive Officer in October 2002 and President
in February 2005. From 2000 to 2002, Mr. Josey served as
Vice President of Enron North America Corp. and co-managed its
Energy Capital Resources group. From 1995 to 2000,
Mr. Josey provided investment banking services to the oil
and gas industry and portfolio management services. From 1993 to
1995, Mr. Josey was a Director with Enron
Capital & Trade Resources Corp. in its energy
investment group. From 1982 to 1993, Mr. Josey worked in
all phases of drilling, production, pipeline, corporate planning
and commercial activities at Texas Oil and Gas Corp.
Mr. Josey is a member of the Society of Petroleum Engineers
and the Independent Producers Association of America.
Dalton F. Polasek Mr. Polasek was
appointed Chief Operating Officer in February 2005. From April
2004 to February 2005, Mr. Polasek served as Executive Vice
President Operations and Exploration. From August
2003 to April 2004, he served as Senior Vice
President Shelf and Onshore. From August 2002 to
August 2003, he was Senior Vice President, and from October 2001
to January 2003, he was a consultant to Mariner. Prior to
joining Mariner, Mr. Polasek was self employed from
February 2001 to October 2001 and served as: Vice President of
Gulf Coast Engineering for Basin Exploration, Inc. from 1996
until February 2001; Vice President of Engineering for SMR
Energy Income Funds from 1994 to 1996; director of Gulf Coast
Acquisitions and Engineering for General Atlantic Resources,
Inc. from 1991 to 1994; and manager of planning and business
development for Mark Producing Company from 1983 to 1991. He
began his career in 1975 as a reservoir engineer for Amoco
Production Company. Mr. Polasek is a Registered
Professional Engineer in Texas and a member of the Independent
Producers Association of America, the American Association of
Drilling Engineers and the American Petroleum Institute.
Rick G. Lester Mr. Lester joined Mariner
as Vice President, Chief Financial Officer and Treasurer in
October 2004. He is leaving Mariner to pursue personal interests
and currently serves as an officer of Mariner
103
under a consulting agreement made effective August 16, 2006
while Mariner continues its search for his successor. See
Employment Agreements and Other
Arrangements. From January 2004 to October 2004,
Mr. Lester was self-employed as a consultant. From 1998 to
2003, Mr. Lester was the Executive Vice President, CFO and
Treasurer of Contour Energy Company (which filed for
Chapter 11 bankruptcy protection in July 2002 and emerged
from bankruptcy in December 2002). From 1991 to 1998,
Mr. Lester held the positions of Vice President, CFO and
Treasurer for Domain Energy Corporation and its Tenneco Ventures
predecessor. Prior to 1991, he held various positions with
Tenneco, Inc. and Tenneco Exploration and Production including
Corporate Finance Manager, International Tax Manager and
Business Division Accounting Manager. Mr. Lester has
over 30 years of industry experience and is a Certified
Public Accountant.
Jesus G. Melendrez Mr. Melendrez was
promoted to Senior Vice President Corporate
Development in April 2006 and served as Vice
President Corporate Development from July 2003 to
April 2006. Mr. Melendrez also served as a director of
Mariner from April 2000 to July 2003. From February 2000 until
July 2003, Mr. Melendrez was a Vice President of Enron
North America Corp. in the Energy Capital Resources group where
he managed the groups portfolio of oil and gas
investments. He was a Senior Vice President of Trading and
Structured Finance with TXU Energy Services from 1997 to 2000,
and from 1992 to 1997, Mr. Melendrez was employed by Enron
in various commercial positions in the areas of domestic oil and
gas financing and international project development. From 1980
to 1992, Mr. Melendrez was employed by Exxon in various
reservoir engineering and planning positions.
Mike C. van den Bold Mr. van den Bold was
promoted to Senior Vice President and Chief Exploration Officer
in April 2006 and served as Vice President and Chief Exploration
Officer from April 2004 to April 2006. From October 2001 to
April 2004, he served as Vice President Exploration.
Mr. van den Bold joined Mariner in July 2000 as Senior
Development Geologist. From 1996 to 2000, Mr. van den Bold
worked for British-Borneo Oil & Gas plc. He began his
career at British Petroleum. Mr. van den Bold has over
17 years of industry experience. He is a Certified
Petroleum Geologist, Texas Board Certified Geologist and member
of the American Association of Petroleum Geologists.
Teresa G. Bushman Ms. Bushman was
promoted to Senior Vice President, General Counsel and Secretary
in April 2006 and served as Vice President, General Counsel and
Secretary from June 2003 to April 2006. From 1996 until joining
Mariner in 2003, Ms. Bushman was employed by Enron North
America Corp., most recently as Assistant General Counsel
representing the Energy Capital Resources group, which provided
debt and equity financing to the oil and gas industry. Prior to
joining Enron, Ms. Bushman was a partner with Jackson
Walker, LLP, in Houston.
Judd A. Hansen Mr. Hansen was promoted
to Senior Vice President Shelf and Onshore in April
2006 and served as Vice President Shelf and Onshore
from February 2002 to April 2006. From October 2001 to February
2002, Mr. Hansen was self-employed as a consultant. From
1997 until March 2001, Mr. Hansen was employed as
Operations Manager of the Gulf Coast Division for Basin
Exploration, Inc. From 1991 to 1997, he was employed in various
engineering positions at Greenhill Petroleum Corporation,
including Senior Production Engineer and Workover/Completion
Superintendent. Mr. Hansen started his career with Shell
Oil Company in 1978 and has 27 years of experience in
conducting operations in the oil and gas industry.
Cory L. Loegering Mr. Loegering has
served as Vice President Deepwater since August
2002. Mr. Loegering joined Mariner in July 1990 and since
1998 has held various positions including Vice President of
Petroleum Engineering and Director of Deepwater development.
Mr. Loegering was employed by Tenneco from 1982 to 1989, in
various positions including as senior engineer in the economic,
planning and analysis group in Tennecos corporate offices.
Mr. Loegering began his career with Conoco in 1977 and held
positions in the construction, production and reservoir
departments responsible for Gulf of Mexico production and
development. Mr. Loegering has 29 years of experience
in the industry.
Richard A. Molohon Mr. Molohon was
appointed Vice President Reservoir Engineering in
May 2006. He joined Mariner in January 1995 as a Senior
Reservoir Engineer and since then has held various positions in
reservoir engineering, economics, acquisitions and dispositions,
exploration, development, and
104
planning and basin analysis, including Senior Staff Engineer
from January 2000 to January 2004, and Manager, Reserves and
Economics from January 2004 to May 2006. Mr. Molohon has
more than 29 years of industry experience. He began his
career with Amoco Production Company as a Production Engineer
from 1977 until 1980. From 1980 to 1991, he was a Project
Petroleum Engineer for various subsidiaries of Tenneco, Inc.
From 1991 to 1995 he was a Senior Acquisition Engineer for
General Atlantic Inc. Mr. Molohon has been a Registered
Professional Engineer in Texas since 1983 and is a member of the
Society of Petroleum Engineers.
Bernard Aronson Mr. Aronson was elected
as a director in March 2004. He is a founding partner of ACON
Investments, a private equity fund. Prior to founding ACON
Investments in 1996, Mr. Aronson was International Advisor
to Goldman Sachs & Co. for Latin America from 1994 to
1996. From 1989 through 1993, Mr. Aronson served as
Assistant Secretary of State for
Inter-American
Affairs. He is a member of the Council on Foreign Relations and
the Presidents Advisory Commission on Trade Promotions and
Negotiations. Mr. Aronson currently serves on the boards of
directors of Liz Claiborne, Inc., Royal Caribbean International
Inc., Tropigas S.A. and Hyatt International Corp.
Alan R. Crain, Jr. Mr. Crain was
elected a director in April 2006. He is Vice President and
General Counsel of Baker Hughes Incorporated and has served in
that capacity since October 2000. He was Executive Vice
President, General Counsel and Secretary of Crown,
Cork & Seal Company, Inc. from 1999 to 2000. He was
Vice President and General Counsel from 1996 to 1999, and
Assistant General Counsel from 1988 to 1996, of Union Texas
Petroleum Holdings, Inc.
Jonathan Ginns Mr. Ginns was elected as
a director in March 2004. He is a founding partner of ACON
Investments. Prior to founding ACON Investments, a private
equity fund, in 1996, Mr. Ginns served as a Senior
Investment Officer for the Global Environment-Emerging Markets
Fund, part of the GEF Funds group, from 1994 to 1995.
Mr. Ginns currently serves on the boards of directors of
The Optimal Group, Signal International and Tropigas S.A.
John F. Greene Mr. Greene was elected as
a director in August 2005. He served as Executive Vice President
of Worldwide Exploration, Production and Natural Gas Marketing
at Louisiana Land & Exploration Company before his
retirement in 1995. Prior to joining Louisiana Land &
Exploration Company, Mr. Greene was the President and Chief
Executive Officer of Milestone Petroleum, Inc. (today,
Burlington Resources, Inc.) from 1981 to 1985. Mr. Greene
served on the board of directors of Colorado-Wyoming Reserves
Company from 1998 through 2004 and as a director and member of
the compensation committee of Basin Exploration, Inc. from 1996
through 2001. Mr. Greene began his career at Conoco and
served in the United States Navy from 1963 until 1968. He is
currently a partner and director of The Shoreline Company and
Leaf River Resources.
H. Clayton Peterson Mr. Peterson
was elected a director in March 2006. During his
33-year
career with Arthur Andersen, he specialized in audits of oil and
gas companies. Most recently, from January 2000 to September
2002, Mr. Peterson was Managing Partner of the Denver
office of Arthur Andersen and Regional Managing Partner of the
audit practices of Arthur Andersen in Tulsa, Oklahoma City and
Dallas. Since September 2002, Mr. Peterson has been a
business consultant, including to the Estate of Kim Magness from
August 2003 to present. He has been a member of the board of
directors of RE/MAX International, Inc. since May 2005 and is
co-chair of its audit committee.
John L. Schwager Mr. Schwager was
elected as a director in August 2005. Prior to his retirement in
2004, Mr. Schwager served as Chief Executive Officer and
President of Belden & Blake Corporation. Before joining
Belden & Blake Corporation in 1999, Mr. Schwager
was the founder and served as President of AnnaCarol
Enterprises, Inc., a consulting firm that provided planning,
advisory, evaluation and management services to the energy
industry. From 1984 until 1997 he served in several management
roles, including President and Chief Executive Officer at
Alamco, Inc. From 1970 through 1984, Mr. Schwager held
various engineering, operations, management and executive
officer positions with Callon Petroleum Company and Shell Oil
Company.
105
Board of
Directors
Under the terms of the Forest Energy Resources merger agreement,
as amended, the Board of Directors of Mariner after completion
of the merger is to be composed initially of seven individuals,
five of whom were directors of Mariner immediately prior to the
merger, one of whom, Mr. Peterson, was mutually agreed upon
by Mariner and Forest prior to, and became a director upon,
completion of the merger, and one of whom, Mr. Crain, was
mutually agreed upon by Mariner and Forest for appointment on
April 1, 2006.
Our certificate of incorporation and bylaws provide for a
classified board of directors consisting of three classes of
directors, each serving staggered three-year terms. As a result,
stockholders will elect a portion of our Board of Directors each
year. The Class I directors term will expire at the
annual meeting of stockholders to be held in 2009, Class II
directors terms will expire at the annual meeting of
stockholders to be held in 2007 and Class III
directors terms will expire at the annual meeting of
stockholders to be held in 2008. Currently, the Class I
directors are Messrs. Aronson, Crain and Peterson, the
Class II directors are Messrs. Greene and Schwager,
and the Class III directors are Messrs. Ginns and
Josey. Effective upon completion of the merger, the directors
increased the board to six and elected Mr. Peterson to fill
the vacancy. On April 1, 2006, the directors increased the
board to seven and elected Mr. Crain to fill the vacancy.
Pursuant to provisions in our certificate of incorporation
regarding vacancies on the Board of Directors,
Messrs. Peterson and Crain must stand for reelection at the
next annual stockholders meeting for a term expiring at the 2009
annual stockholders meeting. At each annual meeting of
stockholders held after the initial classification, the
successors to directors whose terms will then expire will be
elected to serve from the time of election until the third
annual meeting following election. The division of our Board of
Directors into three classes with staggered terms may delay or
prevent a change of our management or a change in control.
In addition, our bylaws provide that the authorized number of
directors, which shall constitute the whole Board of Directors,
may be changed by resolution duly adopted by the Board of
Directors. Any additional directorships resulting from an
increase in the number of directors will be distributed among
the three classes so that, as nearly as possible, each class
will consist of one-third of the total number of directors.
Vacancies and newly created directorships may be filled by the
affirmative vote of a majority of our directors then in office,
even if less than a quorum.
Committees
of the Board
Our Board of Directors has established four committees, the
audit committee, the compensation committee, the nominating and
corporate governance committee, and the executive committee.
Each of Messrs. Aronson, Ginns and Peterson (Chairman) is a
member of our audit committee and is independent
under the listing standards of New York Stock Exchange and SEC
rules. In addition, the Board of Directors has determined that
Mr. Peterson is an audit committee financial
expert, as defined under the rules of the SEC. The audit
committee recommends to the Board of Directors the independent
public accountants to audit our financial statements and
oversees the annual audit. The committee also approves any other
services provided by public accounting firms. The audit
committee provides assistance to the Board of Directors in
fulfilling its oversight responsibility to the stockholders, the
investment community and others relating to the integrity of our
financial statements, our compliance with legal and regulatory
requirements, the independent auditors qualifications and
independence, and the performance of our internal audit
function. The committee oversees our system of disclosure
controls and procedures and system of internal controls
regarding financial, accounting, legal compliance and ethics
that management and the Board of Directors have established. In
doing so, it is the responsibility of the committee to maintain
free and open communication between the committee and our
independent auditors, the internal accounting function and
management of Mariner.
Each of Messrs. Aronson (Chairman), Crain and Greene serves
on the nominating and corporate governance committee of our
Board of Directors and is independent under the
listing standards of the New York Stock Exchange and SEC
rules. This committee nominates candidates to serve on our Board
of Directors and approves director compensation. The committee
also is responsible for monitoring a process to
106
assess board effectiveness, developing and implementing our
corporate governance guidelines and in taking a leadership role
in shaping the corporate governance of Mariner.
Each of Messrs. Ginns, Greene and Schwager (Chairman)
serves on the compensation committee of our Board of Directors
and is independent under the listing standards of
the New York Stock Exchange and SEC rules. The compensation
committee reviews the compensation and benefits of our executive
officers, establishes and reviews general policies related to
our compensation and benefits, and administers our Equity
Participation Plan and Amended and Restated Stock Incentive
Plan. Under the compensation committee charter, the compensation
committee determines the compensation of our CEO.
Each of Messrs. Ginns, Josey (Chairman), Peterson and
Schwager serves on the executive committee of our Board of
Directors. The executive committee may exercise the powers and
authority of the Board in managing the business and affairs of
the Company when the Board is not in session, subject to our
certificate of incorporation, applicable law and any limits on
authority determined from time to time by the Board.
Director
Compensation
Officers and employees who also serve as directors will not
receive additional compensation. For periods before
August 11, 2005, Messrs. Aronson and Ginns did not
receive compensation for their services as directors. For
director services from August 11, 2005 through
March 1, 2006, the Company paid cash compensation on an
annual basis of $40,000 to each of Messrs. Aronson, Ginns,
Greene and Schwager. In addition, on March 31, 2006, the
Company granted each of them 1,100 shares of restricted
stock under the Companys Amended and Restated Stock
Incentive Plan, as amended, with one-third of the shares to vest
upon each of the first three annual meetings of Mariners
stockholders following the date of grant. The 1,100 shares
of restricted stock granted to each of Messrs. Greene and
Schwager replaced an option each received upon his appointment
to the Board in August 2005, exercisable for 4,500 shares
of the Companys common stock at $15.50 per share, and
vesting in
1/3
increments upon each of the three successive annual meetings of
Mariners stockholders following the date of grant. As of
March 31, 2006, neither of these in the money options had
been exercised.
Effective March 2, 2006, non-employee directors will
receive annual compensation for service as a director of
$50,000, and additional annual compensation of $12,500 for
serving on the boards audit committee, $20,000 for serving
as chairman of the audit committee, $5,000 for serving on any
board committee other than the audit committee, and $10,000 for
serving as chairman of any board committee other than the audit
committee. Non-employee directors also will be paid a meeting
fee of $1,500 and $1,000 for attendance or participation by
phone at board meetings and board committee meetings,
respectively. All nonemployee director fees will be paid
quarterly. In addition, each director will be reimbursed for
out-of-pocket
expenses in connection with attending meetings of the Board of
Directors or committees. Each director will be fully indemnified
by us for actions associated with being a director to the extent
permitted under Delaware law.
The Board of Directors authorized a restricted stock grant made
on March 31, 2006 to each nonemployee director and on
April 3, 2006 to Mr. Crain equal to that number of
shares of Mariners common stock with a market value,
determined as of the date of grant, of $50,000, with one-third
of the shares to vest on each of the first three annual meetings
of Mariners stockholders following the date of grant. Each
grant of 2,438 shares on March 31, 2006, based on the
closing price of $20.51 per share, and of 2,465 shares
on April 3, 2006, based on a closing price of
$20.28 per share, was made under Mariners Amended and
Restated Stock Incentive Plan, as amended.
Indemnification
We maintain directors and officers liability
insurance. Our certificate of incorporation and bylaws include
provisions limiting the liability of directors and officers and
indemnifying them under certain circumstances. We have also
entered into indemnification agreements with our executive
officers and directors providing our executive officers and
directors with additional assurances in a manner consistent with
Delaware law.
107
Executive
Compensation
The following table shows the annual compensation for our chief
executive officer and the five other most highly compensated
executive officers for the three fiscal years ended
December 31, 2005.
Summary
Compensation Table
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Long-Term Compensation
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Awards
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Restricted
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Securities
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Payouts
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Annual Compensation
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Stock
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Underlying
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LTIP
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All Other
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Name and Principal Position
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Year
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Salary ($)
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Bonuses($)
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Awards ($)(2)
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Options (#)
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Payouts ($)
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Compensation ($)(3)
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Scott D. Josey
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2005
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$
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375,000
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$
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1,200,000
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$
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$
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$
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16,210
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Chairman of the Board,
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2004
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350,000
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550,000
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9,522,534
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200,000
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575,000
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15,133
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Chief Executive Officer
and President
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2003
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300,290
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850,000
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514,895
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Dalton F. Polasek
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2005
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250,000
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580,000
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16,626
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Chief Operating Officer
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2004
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215,000
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300,000
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4,316,886
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102,000
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248,400
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15,236
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2003
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176,698
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325,000
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280,677
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Mike C. van den Bold
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2005
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200,000
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440,000
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15,819
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Senior Vice President and
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2004
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192,500
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215,000
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3,174,178
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74,000
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322,000
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14,949
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Chief Exploration Officer(1)
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2003
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170,150
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350,000
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45,430
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Judd A. Hansen
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2005
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187,500
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325,000
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15,983
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Senior Vice President
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2004
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180,000
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185,000
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2,221,926
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48,000
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184,000
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15,059
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Shelf and Offshore(1)
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2003
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156,023
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250,000
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109,272
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Rick G. Lester
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2005
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200,000
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300,000
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16,363
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Vice President,
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2004
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43,352
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120,000
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428,512
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40,000
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3,502
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Chief Financial Officer and
Treasurer
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2003
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Teresa G. Bushman
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2005
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200,000
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300,000
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17,197
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Senior Vice President, General
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2004
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190,000
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215,000
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1,920,380
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40,000
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59,800
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14,834
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Counsel and Secretary(1)
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2003
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97,750
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200,000
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23,270
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(1) |
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Mr. van den Bold was Vice President and Chief Exploration
Officer in 2005 and until promoted to indicated position as of
April 27, 2006. Mr. Hansen was Vice
President Shelf and Offshore in 2005 and until
promoted to indicated position as of April 27, 2006.
Ms. Bushman was Vice President, General Counsel and
Secretary in 2005 and until promoted to indicated position as of
April 27, 2006. |
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(2) |
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Dollar amounts are calculated by multiplying the number of
shares of common stock awarded by $14, the trading price of our
common stock on the business day immediately preceding the date
the award was granted. The restricted stock fully vested on
May 31, 2006. For additional information regarding these
grants, please see Equity Participation
Plan. |
At December 31, 2005, the value of all restricted stock
held by each named executive (based on the $17.75 trading price
of our common stock on December 31, 2005) was as
follows:
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Name
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No. of Shares
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Value
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Scott D. Josey
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680,181
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$
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12,073,213
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Dalton F. Polasek
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308,349
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5,473,195
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Mike C. van den Bold
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226,727
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4,024,404
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Judd A. Hansen
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158,709
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2,817,085
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Rick G. Lester
|
|
|
30,608
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|
|
|
543,292
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|
Teresa G. Bushman
|
|
|
137,170
|
|
|
|
2,434,768
|
|
108
|
|
|
(3) |
|
Amounts shown reflect insurance premiums paid by us with respect
to term life insurance for the benefit of the named executive
officers and retention payments paid during the year. The
amounts for 2005 for Messrs. Josey, Polasek, van den Bold,
Hansen and Lester and Ms. Bushman include $7,000 of
employer matching contributions made pursuant to our 401(k) plan
and $8,400 made pursuant to the profit sharing portion of our
401(k) plan. In addition, the 2005 amount includes insurance
premiums under our group term life insurance of $810 for
Mr. Josey, $1,226 for Mr. Polasek, $419 for
Mr. van den Bold, $583 for Mr. Hansen, $963 for
Mr. Lester, and $1,797 for Ms. Bushman. |
Employment
Agreements and Other Arrangements
We entered into an employment agreement with each of the current
executive officers named in the above compensation table. Each
employment agreement has an initial term that runs through
March 2, 2007. The employment agreements automatically
renew each March 3 for an additional one-year period unless
prior notice is given. Each employment agreement provides for a
base salary, a discretionary bonus, and participation in our
benefit plans and programs. Mr. Joseys agreement also
provides for life insurance equal to two times his base salary.
Under the employment agreements, officers are entitled to the
following severance benefits in the event of an officers
resignation for good reason, a termination by us without cause,
upon disability or, in the case of Mr. Joseys
agreement, our non-renewal of the agreement: (i) a lump sum
payment equal to 2.0 (2.5 for Messrs. Polasek, van den Bold
and Hansen, and Ms. Bushman, and 2.99 for Mr. Josey)
times the sum of the officers base salary and three year
average annual bonus, (ii) health care coverage for a
period of eighteen months (two years for Mr. Josey and
Mr. Polasek), (iii) an amount equal to the sum of all
bonuses paid to the officer in the year prior to the year in
which termination occurs, (iv) 100% vesting of all unvested
restricted shares under our Equity Participation Plan (as
discussed under Equity Participation
Plan, all such shares have fully vested), and (v) 50%
vesting of all other unvested rights under any other equity
plans, including our Amended and Restated Stock Incentive Plan.
Subsequent awards under equity plans vest in accordance with
their terms.
The employment agreements also provide for certain change of
control benefits. Upon termination by us for any reason other
than cause at any time within nine months after a change of
control that occurs while the executive is employed, or upon the
occurrence of a change of control within nine months following
an officers resignation of employment for good reason or
termination by us without cause, the agreements provide for the
following benefits: (i) a lump sum payment equal to 2.0
(2.5 for Messrs. Polasek, van den Bold and Hansen, and
Ms. Bushman, and 2.99 for Mr. Josey) times the sum of
the officers base salary and three year average annual
bonus, and (ii) 100% vesting of all unvested rights under
any equity plans, including our Amended and Restated Stock
Incentive Plan. The officers are entitled to a full tax
gross-up
payment if the aggregate payments and benefits to be provided
constitute a parachute payment subject to a Federal
excise tax.
The executive officers of Mariner became entitled to receive
cash payments of $1,000 each in exchange for the waiver of
certain rights under their employment agreements, including the
automatic vesting or acceleration of restricted stock and
options upon the completion of the merger with Forest Energy
Resources and the right to receive a lump sum cash payment if
the officer voluntarily terminates employment without good
reason within nine months following the completion of the merger.
The agreements also include confidentiality and non-solicitation
provisions.
The term of Mr. Lesters employment agreement expired
upon his resignation as an employee effective August 15,
2006. He is leaving Mariner to pursue personal interests and
currently serves as an officer of Mariner under a consulting
agreement made effective August 16, 2006 while Mariner
continues its search for his successor. Under the consulting
agreement, Mr. Lester has agreed to perform finance,
accounting and other services on a consulting basis, continue to
serve in his capacity as an officer of Mariner, and assist in
transition upon the hiring of his successor. The consulting
agreement, which can be terminated by either party upon
30 days notice, provides that Mariner pay
Mr. Lester $2,300 per day for his services. In
connection with
109
Mr. Lesters resignation as an employee, Mariner
agreed to pay him a bonus in the amount of $237,500 in respect
of his performance in 2006 as an employee.
Overriding
Royalty Arrangements
Mariners geologist and geophysicist employees are eligible
to participate in Mariners Amended and Restated Gulf of
Mexico Overriding Royalty Interest Plan. Pursuant to the terms
of the plan, overriding royalty interests (ORRIs)
may be awarded to participants in the plan for prospects in the
Gulf of Mexico that are generated or identified and acquired
during the term of the participants employment at Mariner.
The maximum ORRI for all participants is 1.8% for shelf leases
and 0.9% for deepwater leases, subject to proportionate
reduction. The maximum ORRI per participant is 1/2 of one
percent for shelf leases and 1/4 of one percent for deepwater
leases, subject to proportionate reduction. Unless approved by
Mariners overriding royalty interest committee, no ORRIs
are awarded for developed or undeveloped reserve acquisitions.
Certain of the Forest Gulf of Mexico leases not covering
developed or undeveloped reserves may become burdened by ORRIs
under the plan as determined by such committee in accordance
with the terms of the plan. None of the members of the committee
is eligible to participate in the plan.
To avoid potential conflicts of interest, Mariners
geologist and geophysicist employees that participate in the
Overriding Royalty Interest Plan (the ORRI Plan
Participants) do not make decisions with respect to the
pursuit of the acquisition, exploration or development of
prospects. When an ORRI Plan Participant develops a lead for a
prospect, executive management makes the decision whether to
pursue to the acquisition, exploration or development of the
prospect. In addition, ORRI Plan Participants are required at
the time they become eligible for participation in the plan and
periodically thereafter to disclose oil and gas properties in
which they or their immediate family members have any interest
and to abstain from participation in the evaluation of any
property in which they or their immediate family members have
any interest.
As of December 31, 2005, six employees participated in the
plan. None of Mariners officers or managers are eligible
to participate in the plan. Since the inception of the plan in
July 2002 through December 31, 2005, approximately $584,000
has been distributed to participants with respect to ORRIs
granted to them under the plan, of which $332,000 was
distributed in 2005.
In 2002, two of our current executive officers, Dalton F.
Polasek, Chief Operating Officer, and Judd A. Hansen, Senior
Vice President Shelf and Onshore, received
assignments of ORRIs in certain leases acquired by us under a
consulting arrangement. A consulting company owned in part by
Mr. Polasek was assigned a 2% ORRI from us in four federal
offshore leases as partial consideration for having brought the
related prospect to us. With our knowledge and consent, the
consulting company subsequently assigned portions of the ORRIs
to Mr. Hansen and a company owned by Mr. Polasek. At
the time of the assignments, Messrs. Polasek and Hansen
served Mariner as officers and consultants but were not employed
by Mariner. No payments were made in respect of these ORRIs
until 2004, when each received less than $60,000 with respect to
his ORRI. No payments were made in respect of these ORRIs in
2005.
We may have obligations under previously terminated employment
and consulting agreements to assign additional ORRIs in some of
our oil and natural gas prospects to current and former
employees and consultants. Cory L. Loegering, Vice
President Deepwater, and Richard A. Molohon, Vice
President Reservoir Engineering, are the only
current executive officers who may be entitled to receive ORRIs
from time to time under any of these agreements. Mariner made
net cash payments to each of Mr. Loegering of $378,312,
$368,095 and $205,245 in 2005, 2004 and 2003, respectively, and
Mr. Molohon of $282,153, $274,364 and $151,482 in 2005,
2004 and 2003, respectively in respect of ORRIs assigned from
time to time pursuant to a right to receive such ORRIs that was
granted in 2002.
All ORRIs assigned to these parties are excluded from
Mariners interests evaluated in our reserve report.
Equity
Participation Plan
We adopted an Equity Participation Plan administered by our
Board of Directors that provided for the one-time grant at the
closing of our private equity placement on March 11, 2005
of 2,267,270 restricted shares
110
of our common stock to certain of our employees. No further
grants will be made under the Equity Participation Plan,
although persons who received such a grant may be eligible for
future awards of restricted stock or stock options under our
Amended and Restated Stock Incentive Plan described below.
We intended the grants of restricted stock under the Equity
Participation Plan to serve as a means of incentive compensation
for performance and not primarily as an opportunity to
participate in the equity appreciation of our common stock.
Therefore, Equity Participation Plan grantees did not pay any
consideration for the common stock they received, and we
received no remuneration for the stock.
The table below includes information regarding the restricted
stock awards granted in March 2005 under the Equity
Participation Plan to our chief executive officer, our five
other most highly compensated executive officers as of the year
ended 2005, and all officers as a group as of December 31,
2005.
Equity
Participation Plan
Restricted
Stock Awards
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|
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|
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Officer or Group
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No. of Shares
|
|
|
Value at Grant(1)
|
|
|
Scott D. Josey
|
|
|
680,181
|
|
|
$
|
9,522,534
|
|
Dalton F. Polasek
|
|
|
308,349
|
|
|
|
4,316,886
|
|
Mike C. van den Bold
|
|
|
226,727
|
|
|
|
3,174,178
|
|
Judd A. Hansen
|
|
|
158,709
|
|
|
|
2,221,926
|
|
Rick G. Lester
|
|
|
30,608
|
|
|
|
428,512
|
|
Teresa G. Bushman
|
|
|
137,170
|
|
|
|
1,920,380
|
|
Officers as a group
(8 persons)
|
|
|
1,803,614
|
|
|
|
25,250,596
|
|
|
|
|
(1) |
|
Based on a price of $14.00 per share. |
In connection with the merger with Forest Energy Resources, all
shares of restricted stock granted under the Equity
Participation Plan vested as follows: (i) the
463,656 shares of restricted stock held by non-executive
employees vested on March 2, 2006, and (ii) the
1,803,614 shares of restricted stock held by executive
officers vested on May 31, 2006 pursuant to an agreement,
made in exchange for a cash payment of $1,000 to each officer,
that his or her shares of restricted stock would not vest before
the later of March 11, 2006 or ninety days after the
effective date of the merger. The Equity Participation Plan
expired upon the vesting of all shares granted thereunder.
Stock could be withheld by us upon vesting to satisfy our tax
withholding obligations with respect to the vesting of the
restricted stock. Participants in the Equity Participation Plan
had the right to elect to have us withhold and cancel shares of
the restricted stock to satisfy withholding obligations. In such
events, we would be required to pay any tax withholding
obligation in cash. As a result of such participant elections,
we withheld an aggregate 807,376 shares that otherwise
would have remained outstanding upon vesting of the restricted
stock, reducing the aggregate outstanding vested stock grants
made under the Equity Participation Plan to
1,459,894 shares. The 807,376 shares withheld became
treasury shares that were retired and restored to the status of
authorized and unissued shares of common stock. We paid the
associated withholding taxes in cash.
In accordance with GAAP, we expect to incur significant
compensation expense as a result of the grants of restricted
stock under the Equity Participation Plan. See
Managements Discussion and Analysis of Financial
Condition and Results of Operations Critical
Accounting Policies and Estimates Compensation
Expense for a discussion of these charges.
Amended
and Restated Stock Incentive Plan
We adopted a Stock Incentive Plan which became effective
March 11, 2005 and was amended and restated on
March 2, 2006. The objectives of the Amended and Restated
Stock Incentive Plan are to encourage employees and directors to
acquire or increase their equity interest with Mariner and to
provide a means
111
whereby they may develop a sense of proprietorship and personal
involvement in the development and financial success of Mariner.
The Amended and Restated Stock Incentive Plan is also designed
to enhance Mariners ability to attract and retain the
services of individuals who are essential for the growth and
profitability of Mariner.
Awards to participants under the Amended and Restated Stock
Incentive Plan may be made in the form of incentive stock
options, or ISOs, non-qualified stock options or restricted
stock. The participants to whom awards are granted, the type or
types of awards granted to a participant, the number of shares
covered by each award, the purchase price, conditions and other
terms of each award are determined by the Board of Directors or
the committee appointed by the Board of Directors to administer
the Amended and Restated Stock Incentive Plan (the
Committee).
Shares Subject
to the Amended and Restated Stock Incentive Plan
A total of 6.5 million shares of Mariners common
stock is subject to the Amended and Restated Stock Incentive
Plan. No more than 2.85 million shares issuable upon
exercise of options or as restricted stock can be issued to any
individual. As of September 30, 2006, 4,966,071 shares
remained available under the Amended and Restated Stock
Incentive Plan for future issuance to participants.
Administration
and Eligibility
The Committee has the authority to administer the Amended and
Restated Stock Incentive Plan and to take all actions that are
specifically contemplated by the Amended and Restated Stock
Incentive Plan or are necessary or appropriate in connection
with the administration of the Amended and Restated Stock
Incentive Plan. The Committee has the full power and authority
to designate participants, determine the type or types of
awards, the number of shares to be covered by awards, and the
terms and conditions of any award. The Committee also determines
whether, to what extent, and under what circumstances awards may
be settled or exercised in cash, shares or other securities,
other awards or other property, or canceled, forfeited or
suspended and the method or methods by which awards may be
settled, exercised, canceled, forfeited or suspended. The
Committee has the authority to establish, amend, suspend or
waive such rules and regulations, and appoint such agents as it
shall deem appropriate, and make any other determination or take
any other action the Committee deems necessary for the proper
administration of the Amended and Restated Stock Incentive Plan.
Any employee of Mariner (or any parent entity or subsidiary) and
any non-employee director of Mariner is eligible to be
designated a participant by the Committee. As of
December 31, 2005, two non-employee directors and 51
employees had been granted awards under the Amended and Restated
Stock Incentive Plan.
Awards
Awards may, in the discretion of the Committee, be granted
either alone or in addition to, or in tandem with, any other
award granted under the Amended and Restated Stock Incentive
Plan or any award granted under any other plan of Mariner or any
parent entity or subsidiary. Awards granted in addition to or in
tandem with other awards or awards granted under any other plan
of Mariner or any parent entity or subsidiary may be granted
either at the same time as or at a different time from the grant
of such other awards. All or part of an award may be subject to
conditions established by the Committee.
The types of awards to participants that may be made under the
Amended and Restated Stock Incentive Plan are as follows:
Options. Options are rights to purchase a
specified number of shares of common stock at a specified price.
The Committee will determine the participants to whom options
are granted, the number of shares to be covered by each option,
the purchase price and the conditions, which of the options is
an ISO or a nonqualified stock option, and limitations
applicable to the exercise of the option. To the extent that the
aggregate fair market value, determined at the time the
respective ISO is granted, of common stock with respect to which
ISOs are exercisable for the first time by an individual during
any calendar year under all incentive stock option plans of
Mariner and its parent and subsidiary corporations exceeds
112
$100,000, or such option fails to constitute an ISO for any
reason, such purported ISOs will be treated as non-qualified
stock options.
ISOs may be granted only to an individual who is an employee of
Mariner or any parent or subsidiary corporation at the time the
option is granted. The Committee determines the exercise price
at the time each option is granted, but the exercise price shall
never be less than the fair market value per share on the
effective date of such grant. The Committee determines the time
or times at which each option may be exercised, the method or
methods by which, and the form or forms in which, payment of the
exercise price may be made or deemed to have been made.
An ISO must be granted within 10 years from the date the
Amended and Restated Stock Incentive Plan was approved by the
Board or the shareholders, whichever is earlier. No ISO shall be
granted to an individual if, at the time the ISO is granted,
such individual owns stock possessing more than 10% of the total
combined voting power of all classes of stock of Mariner or of
its parent or subsidiary corporation, unless:
|
|
|
|
|
at the time the ISO is granted, the option price is at least
110% of the fair market value of the common stock subject to the
option; and
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|
|
|
such ISO, by its terms, is not exercisable after the expiration
of five years from the date of grant.
|
Options are not transferable, other than by will or the laws of
descent and distribution, and are exercisable during the
participants lifetime only by the participant or the
participants guardian or legal representative.
Restricted Stock. Restricted stock is stock
that has limitations placed on it. Dividends paid on restricted
stock may be paid directly to the participant, sequestered and
held in a bookkeeping account, or reinvested in additional
shares, which may be subject to the same restrictions as the
underlying award or other restrictions, as determined by the
Committee. Restricted stock is evidenced in such manner as
deemed appropriate by the Committee, but any stock certificate
that is issued in respect of restricted stock granted under the
Amended and Restated Stock Incentive Plan must be registered
under the participants name and bear an appropriate legend
referring to the terms, conditions and restrictions applicable
to the restricted stock.
Unless otherwise determined by the Committee or provided in an
award agreement, upon termination of a participants
employment for any reason during the applicable restricted
period, which is the period established by the Committee with
respect to an award during which the award either remains
subject to forfeiture or is not transferable by the participant,
all restricted stock is forfeited without payment and reacquired
by Mariner. The Committee may waive in whole or in part any or
all remaining restrictions on such participants restricted
stock, but if such award was intended to qualify as
performance-based compensation, then only upon an event
permitted under Section 162(m) of the Code. Restricted
stock is subject to such limitations on transfer as are
necessary to comply with Section 83 of the Code.
Other
Provisions
Unless sooner terminated, no award may be granted under the
Amended and Restated Stock Incentive Plan after October 12,
2015. The Board of Directors or the Committee may amend, alter,
suspend, discontinue or terminate the Stock Incentive Plan
without the consent of any stockholder, participant, other
holder or beneficiary of an award or any other person. However,
no amendment may materially adversely affect the rights of a
participant under an award without the consent of such
participant.
In the event of any distribution, recapitalization,
reorganization, merger, spin-off, split-off, split-up,
consolidation, combination, repurchase, or exchange of shares or
other securities of Mariner or any other
113
relevant corporate transaction or event or any unusual or
nonrecurring transactions or events affecting Mariner, the
Committee may, in its sole discretion and on such terms and
conditions as it deems appropriate:
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|
|
provide for either the termination of any such award in exchange
for cash in the amount that would have been attained upon the
exercise of such award or the replacement of such award with
other rights or property selected by the Committee;
|
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|
|
provide that such award be assumed by the successor or survivor
corporation or its parent or be substituted for by similar
options, rights or awards; or
|
|
|
|
make adjustments in the number and type of shares or other
property subject to outstanding awards.
|
Amended
and Restated Stock Incentive Plan Benefits
Because the granting of awards under the Amended and Restated
Stock Incentive Plan is at the discretion of the Committee, it
is not now possible to determine which persons may be granted
awards. Also, it is not now possible to estimate the number of
shares of common stock that may be awarded under the Amended and
Restated Stock Incentive Plan.
U.S. Federal
Tax Consequences
The following is a general discussion of the current Federal
income tax consequences of awards under the Amended and Restated
Stock Incentive Plan to participants who are classified as
U.S. residents for Federal income tax purposes. Different
or additional rules may apply to participants who are subject to
income tax in a foreign jurisdiction
and/or are
subject to state or local income tax in the United States. Each
participant should rely on his or her own tax advisors regarding
federal income tax treatment under the Amended and Restated
Stock Incentive Plan.
Restricted
Stock
The grant of restricted stock does not result in taxable income
to the participant. At each vesting event, the participant will
recognize taxable ordinary income equal to the excess of the
fair market value of the shares of common stock that become
vested over the purchase price (if any) paid for such common
stock. However, if a participant makes a timely election under
Section 83(b) of the Code, the participant will recognize
taxable ordinary income in the taxable year of the grant equal
to the excess of the fair market value of the shares of common
stock underlying the restricted stock award at the time of the
grant over the purchase price (if any) paid for such common
stock. Furthermore, the participant will not recognize ordinary
income on such restricted stock when it subsequently vests.
In all cases, the participants ordinary income is subject
to applicable withholding taxes. Mariner will be allowed an
income tax deduction in the taxable year the participant
recognizes ordinary income, in an amount equal to such ordinary
income.
Stock
Options
The grant of a non-qualified stock option will not result in
taxable income to the participant and Mariner will not be
entitled to an income tax deduction. Upon the exercise of a
non-qualified stock option, a participant will realize ordinary
taxable income on the date of exercise. Such taxable income will
equal the difference between the fair market value of the common
stock on the date of exercise and the option price. Mariner will
be entitled to an income tax deduction equal to the amount
included in the participants ordinary income.
Upon the grant or exercise of an ISO, a participant will not
recognize taxable income and Mariner will not be entitled to an
income tax deduction. However, the exercise of an ISO will
result in an amount being included in the participants
alternative minimum taxable income for the year in which the
exercise occurs equal to the excess of the fair market value of
the common stock purchased under the ISO at the time of exercise
over the option price.
114
The optionee will recognize taxable income in the year in which
the shares of common stock underlying the ISO are sold or
disposed of. Dispositions are divided into two categories:
qualifying and disqualifying. A qualifying disposition occurs if
the sale or disposition is made more than two years from the
option grant date and more than one year from the exercise date.
If the participant sells or disposes of the shares of common
stock in a qualifying disposition, any gain recognized by the
participant on such sale or disposition will be a long-term
capital gain.
If either of the two holding periods described above are not
satisfied, then a disqualifying disposition will occur. If the
optionee makes a disqualifying disposition of the shares of
common stock that have been acquired through the exercise of the
option, then the optionee will have ordinary taxable income for
the taxable year in which the sale or disposition occurs equal
to the lesser of:
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the excess of the fair market value of such shares on the option
exercise date over the exercise price paid for the
shares; or
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the amount realized on the sale or disposition over the exercise
price paid for the shares.
|
If the optionee makes a qualifying disposition, Mariner will not
be entitled to an income tax deduction. However, if the optionee
makes a disqualifying disposition, Mariner will be entitled to
an income tax deduction equal to the amount included in ordinary
income to the participant.
The table below includes information regarding stock options
under the Amended and Restated Stock Incentive Plan granted in
our last fiscal year to our chief executive officer and our five
other most highly compensated executive officers.
Option
Grants in Last Fiscal Year
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% of Total
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Options
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Potential Realizable
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No. of
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Granted to
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Value of Assumed
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Securities
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Employees
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Annual Rates of
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Underlying
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in Fiscal
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Exercise
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Expiration
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Stock Price Appreciation for Option Term(1)
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Name
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Options
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Year
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Price
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|
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Date
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|
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5%($)
|
|
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10%($)
|
|
|
Scott D. Josey
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200,000
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24.7
|
%
|
|
$
|
14.00
|
|
|
|
3/11/2015
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$
|
1,760,905
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$
|
4,462,479
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Dalton F. Polasek
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102,000
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|
|
12.6
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|
|
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14.00
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|
|
|
3/11/2015
|
|
|
|
898,062
|
|
|
|
2,275,864
|
|
Mike C. van den Bold
|
|
|
74,000
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|
|
|
9.1
|
|
|
|
14.00
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|
|
|
3/11/2015
|
|
|
|
651,535
|
|
|
|
1,651,117
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|
Judd A. Hansen
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|
|
48,000
|
|
|
|
5.9
|
|
|
|
14.00
|
|
|
|
3/11/2015
|
|
|
|
422,617
|
|
|
|
1,070,995
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|
Rick G. Lester
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40,000
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(2)
|
|
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4.9
|
|
|
|
14.00
|
|
|
|
3/11/2015
|
|
|
|
352,181
|
|
|
|
892,496
|
|
Teresa G. Bushman
|
|
|
40,000
|
|
|
|
4.9
|
|
|
|
14.00
|
|
|
|
3/11/2015
|
|
|
|
352,181
|
|
|
|
892,496
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|
|
|
|
(1) |
|
In accordance with SEC rules, these columns show gain that could
accrue for the listed options, assuming that the market price
per share of our common stock appreciates from the date of grant
over a period of 10 years at an annualized rate of 5% and
10%, respectively. If the stock price does not increase above
the exercise price at the time of exercise, the realized value
from these options will be zero. |
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(2) |
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This option expired unexercised on August 15, 2006. |
115
SECURITY
OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as of
September 30, 2006 (except as otherwise indicated) with
respect to the beneficial ownership of Mariners common
stock by (i) 5% stockholders, (ii) current directors,
(iii) six most highly compensated executive officers during
2005 and (iv) current executive officers and directors as a
group.
Unless otherwise indicated in the footnotes to this table, each
of the stockholders named in this table has sole voting and
investment power with respect to the shares indicated as
beneficially owned.
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Percent of
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Name of Beneficial Owner(1)
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Amount(2)
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Class
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5% Stockholder:
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FMR Corp.(3)
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14,167,849
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16.4
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%
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Officers and
Directors(4):
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Scott D. Josey(5)
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633,571
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*
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Dalton F. Polasek(6)
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305,229
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*
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Mike C. van den Bold(7)
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212,227
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*
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Judd A. Hansen(8)
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157,051
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*
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Rick G. Lester
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22,512
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*
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Teresa G. Bushman(9)
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132,522
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*
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Bernard Aronson(10)
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3,410,362
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4.0
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%
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Alan R. Crain, Jr.
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2,465
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|
*
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Jonathan Ginns(11)
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3,408,745
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4.0
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%
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John F. Greene
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11,775
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*
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H. Clayton Peterson
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3,651
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|
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*
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John L. Schwager
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3,538
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|
|
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*
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Executive officers and directors
as a group (15 persons)(12)
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5,063,320
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5.9
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%
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(1) |
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As of September 30, 2006, Mariner had
86,269,563 shares of common stock issued and outstanding.
As of that date, the only stockholder of record holding more
than 5% of Mariners issued and outstanding common stock
was CEDE & CO (FAST) which held of record 80,547,284 or
93.4% of such shares. Mariner understands that CEDE &
CO (FAST) does not beneficially own such shares and as of
September 30, 2006, had not been able to ascertain whether
any of the beneficial owners of such shares owned more than 5%
of Mariners issued and outstanding common stock except as
indicated in footnote (3) below. CEDE & CO
(FAST)s address is PO Box 20, Bowling Green Station,
New York, NY 10004. |
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(2) |
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Includes grants of restricted stock to directors and certain
executive officers under our Amended and Restated Stock
Incentive Plan. These shares may be voted, but not disposed of,
prior to vesting. Also includes shares issuable upon exercise of
presently exercisable options held by certain of the indicated
persons. |
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(3) |
|
A Schedule 13G filed with the Securities and Exchange
Commission by FMR Corp. on April 10, 2006 (the
13G) indicates that no one persons interest in
the indicated shares is more than five percent of Mariners
outstanding common stock, that FMR Corp. beneficially owns and
has sole power to dispose or to direct the disposition of 100%
of the indicated shares, and that FMR Corp. has sole power to
vote or direct the vote of 1,066,618 of the indicated shares.
The 13G discloses that Fidelity Management & Research
Company, a wholly-owned subsidiary of FMR Corp. and an
investment adviser registered under the Investment Advisers Act
of 1940, is the beneficial owner of 13,225,660 of the indicated
shares as a result of acting as investment adviser to various
investment companies registered under the Investment Company Act
of 1940. The 13G further discloses that Edward C. Johnson 3d and
FMR Corp., through its control of Fidelity Management &
Research Company, and the funds each has sole power to dispose |
116
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of the 13,225,660 shares owned by the funds, and that the
Boards of Trustees of the funds have sole power to vote or
direct the voting of the shares owned by the funds, with
Fidelity Management & Trust Company carrying out the
voting of the shares under written guidelines established by the
funds Boards of Trustees. The 13G notes that
Mr. Johnson is the Chairman of FMR Corp. and that members
of his family may, as a result of certain security ownership in
FMR Corp. and a related voting agreement, be deemed, under the
Investment Company Act of 1940, to form a controlling group with
respect to FMR Corp. The 13G also discloses that Fidelity
Management Trust Company, a wholly-owned subsidiary of FMR Corp.
and a bank as defined in Section 3(a)(6) of the Securities
Exchange Act of 1934, is the beneficial owner of 942,189 of the
indicated shares as a result of its serving as investment
manager of institutional account(s). The 13G further discloses
that Mr. Johnson and FMR Corp., through its control of
Fidelity Management Trust Company, each has sole dispositive
power over, and sole power to vote or to direct the voting of,
the 942,189 shares owned by such institutional account(s).
The 13G reports the address of each of FMR Corp., Fidelity
Management & Research Company and Fidelity Management
Trust Company as 82 Devonshire Street, Boston, Massachusetts
02109. This description of the 13G is qualified by reference to
the 13G. |
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(4) |
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The address of each officer and director is c/o Mariner
Energy, Inc., One Briar Lake Plaza, Suite 2000,
2000 West Sam Houston Parkway South, Houston, Texas 77042. |
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(5) |
|
Includes 66,667 shares issuable upon exercise of a
presently exercisable option. |
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(6) |
|
Includes 34,000 shares issuable upon exercise of a
presently exercisable option. |
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(7) |
|
Includes 24,667 shares issuable upon exercise of a
presently exercisable option. |
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(8) |
|
Includes 16,000 shares issuable upon exercise of a
presently exercisable option. |
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(9) |
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Includes 13,334 shares issuable upon exercise of a
presently exercisable option. |
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(10) |
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Mr. Aronson indirectly owns 1,213 shares that are
directly owned by the Bolivar International Defined Benefit
Pension Plan and 404 shares that are directly owned by his
IRA. Mr. Aronson may be deemed to be a beneficial owner of
1,895,630 shares and 1,509,577 shares that are
beneficially owned by ACON E&P, LLC and ACON Investments
LLC, respectively. MEI Acquisitions Holdings, LLC is the record
holder of the shares beneficially owned by ACON E&P, LLC.
MEI Investment Holdings, LLC is the holder of the shares
beneficially owned by ACON Investments LLC. Mr. Aronson is
a manager of ACON E&P, LLC and a managing member of ACON
Investments LLC, the managing member of MEI Investment Holdings,
LLC. Mr. Aronson disclaims beneficial ownership of these
shares except to the extent of his pecuniary interest therein.
Mr. Aronsons address is c/o ACON Investments,
LLC, 1133 Connecticut Avenue, N.W., Suite 700,
Washington, D.C. 20036. |
|
(11) |
|
Mr. Ginns may be deemed to be a beneficial owner of
1,895,630 shares and 1,509,577 shares that are
beneficially owned by ACON E&P, LLC and ACON Investments
LLC, respectively. MEI Acquisitions Holdings, LLC is the record
holder of the shares beneficially owned by ACON E&P LLC. MEI
Investment Holdings, LLC is the holder of the shares
beneficially owned by ACON Investments LLC. Mr. Ginns is a
managing member of Burns Park Investments LLC, a manager of ACON
E&P, LLC. Mr. Ginns is a managing member of ACON
Investments LLC, the managing member of MEI Investment Holdings,
LLC. Mr. Ginns disclaims beneficial ownership of these
shares except to the extent of his pecuniary interest therein.
Mr. Ginns address is c/o ACON Investments, LLC,
1133 Connecticut Avenue, N.W., Suite 700,
Washington, D.C. 20036. |
|
(12) |
|
Includes 199,336 shares issuable upon exercise of presently
exercisable options. |
117
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with Mariners merger in March 2004, Mariner
Energy LLC, our former indirect parent, entered into management
agreements with each of Carlyle/Riverstone Energy
Partners II, L.P. (C/R Energy Partners) and
ACON E&P III, LLC (ACON E&P), pursuant
to which C/R Energy Partners and ACON E&P received aggregate
fees in the amount of $2.5 million. C/R Energy Partners
was, and ACON E&P is, an affiliate of MEI Acquisitions
Holdings, LLC, our former sole stockholder. No additional fees
are payable under these agreements.
Under a C/R Monitoring Agreement with C/R Energy Partners and
under an ACON Monitoring Agreement with ACON E&P, each dated
as of March 2, 2004, we were obligated to pay monitoring
fees in the aggregate amount of 1% of our annual consolidated
EBITDA to C/R Energy Partners and ACON E&P payable on a
calendar quarter basis. Under the terms of the monitoring
agreements, the affiliates provided financial advisory services
in connection with the ongoing operations of Mariner subsequent
to the merger. We accrued $1.4 million in monitoring fees
under these agreements for 2004. The parties terminated these
agreements on February 7, 2005 in return for lump sum cash
payments by Mariner totaling $2.3 million. We intend to
engage in transactions with our affiliates in the future only
when the terms of any such transactions are no less favorable
than transactions that could be obtained from third parties.
We used $166 million of the net proceeds from our sale of
12,750,000 shares of common stock in our 2005 private
placement to purchase and retire an equal number of shares of
our common stock shares then held by MEI Acquisitions Holdings,
LLC, our former sole stockholder.
The estimated $1.9 million in expenses related to the March
2005 private placement included approximately $0.8 million
of expenses incurred by our former sole stockholder, MEI
Acquisitions Holdings, LLC, and its members in connection with
the offering.
We currently have obligations concerning ORRI arrangements with
two of our officers who received assignments of ORRIs in certain
leases acquired by us under a consulting agreement and with two
other officers who may be entitled to assignments of ORRIs under
previously terminated employment and consulting agreements, as
described in Management Overriding Royalty
Arrangements.
118
DESCRIPTION
OF EXISTING INDEBTEDNESS
Secured
Bank Credit Facility
In January 2006, the borrowing base under our revolving secured
credit facility was increased to $185 million. In
connection with the merger with Forest Energy Resources on
March 2, 2006, we amended and restated our existing credit
facility to increase maximum credit availability to
$500 million for revolving loans, including up to
$50 million in letters of credit, with a $400 million
borrowing base as of that date. On March 2, 2006, after
giving effect to funds required at closing to refinance
$176.2 million of debt assumed in the merger and other
merger-related costs, our total debt drawn under the facility
was approximately $350 million, including a
$4.2 million letter of credit required for plugging and
abandonment obligations at one of our offshore fields. On
April 7, 2006, the borrowing base under the secured credit
facility was increased to $430 million, subject to
redetermination or adjustment. On April 24, 2006, the
borrowing base was reduced to $362.5 million in accordance
with an amendment to the revolving credit facility related to
our offering of the old notes. For subsequent qualifying bond
issuances, the amendment provides that the borrowing base in
effect on the closing date of such a bond issuance will
automatically reduce by 25% of the aggregate principal amount of
such bond issuance to the extent that it does not refinance the
principal amount of an existing bond issuance. The secured
credit facility permits Mariners issuance of certain
unsecured bonds of up to $350 million in aggregate
principal amount that have a non-default interest rate of 10% or
less per annum and a scheduled maturity date after March 1,
2012. Mariners sale and issuance of the old notes and the
new notes were and will be, respectively, such a qualifying bond
issuance. At June 30, 2006, approximately
$161.2 million was outstanding under our revolving secured
credit facility, including the $4.2 million letter of
credit. We anticipate that the borrowing base will be increased
to $450 million in October 2006, subject to redetermination
or adjustment. This credit facility matures on March 2,
2010.
The amendment and restatement of our secured credit facility on
March 2, 2006 also provided for an additional
$40 million letter of credit for the benefit of Forest to
guarantee certain drilling obligations in West Texas. This
letter of credit is not included as a use of our borrowing base
availability and matures on March 2, 2009. The amount of
the letter of credit is to reduce periodically, with the
reduction amount depending upon the number of wells drilled.
Based upon the number of wells drilled as of September 30,
2006, the first reduction is expected in October 2006.
Interest under the revolving credit facility is determined by
reference to the following grid:
Applicable
Margin
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|
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|
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|
|
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|
|
Reference
|
|
|
|
|
Usage as a % of Borrowing Base
|
|
LIBOR Loans
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|
|
Rate Loans
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|
|
Unused Fee
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|
|
Less than 50%
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|
|
1.25
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%
|
|
|
0.00
|
%
|
|
|
0.375
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%
|
51% to 75%
|
|
|
1.50
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%
|
|
|
0.00
|
%
|
|
|
0.375
|
%
|
76% to 90%
|
|
|
1.75
|
%
|
|
|
0.25
|
%
|
|
|
0.250
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%
|
Greater than 90%
|
|
|
2.00
|
%
|
|
|
0.50
|
%
|
|
|
0.250
|
%
|
Interest is payable quarterly for Union Bank of California
Reference Rate loans and at the applicable maturity date (or, if
the maturity date is longer than three months, on each
three-month anniversary date) for LIBOR (London interbank
offered rate) loans. The fee for letters of credit issued under
the revolving credit facility is the LIBOR margin indicated in
the grid, per annum. The fee for letters of credit under the
letter of credit facility is 1.50% due quarterly in advance.
The obligations under the credit facilities are secured by first
priority liens on substantially all of our real and personal
property, including our existing and after-acquired oil and gas
properties and related real property interests. Additionally,
the obligations under the credit facilities are guaranteed by us
and each of our subsidiaries.
119
The credit facilities contain various covenants that limit our
ability to do the following, among other things:
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incur certain indebtedness;
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|
grant certain liens;
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|
merge or consolidate with another entity;
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|
sell property or other assets which generate proceeds in excess
of 5% of the then current borrowing base;
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|
make certain loans or investments, or dividends or other
payments in respect of equity;
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|
make optional prepayments in respect of the notes, except
optional prepayments (i) of 50% or less of the then
outstanding principal amount of the notes which are made
promptly with the proceeds Mariner receives from an offering of
its equity securities registered under the Securities Act, and
(ii) to refinance the notes with the proceeds Mariner
receives from the issuances of certain qualifying debt;
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|
enter into speculative hedging transactions; and
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|
|
enter new lines of business.
|
The credit facilities also contain covenants, which, among other
things, require us to maintain specified ratios as follows:
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|
|
consolidated current assets plus the unused borrowing base to
consolidated current liabilities of not less than 1.0 to
1.0; and
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|
|
|
total debt to consolidated EBITDA of not more than 2.5 to 1.0.
|
We were in compliance with the financial covenants under the
bank credit facility as of June 30, 2006.
If an event of default exists under the credit facilities, the
lenders will be able to accelerate the maturity of the credit
facilities and exercise other rights and remedies. Events of
default include defaults in payment or performance under the
credit facilities, misrepresentations, cross-defaults to other
debt or material obligations, and insolvency, material adverse
judgments, change of control (including certain changes in
ownership and in the event Mr. Scott D. Josey ceases to be
involved in Mariners management, the failure to timely
replace him with someone with comparable qualifications) and any
material adverse change.
As of December 31, 2005, $4 million was outstanding
under the JEDI note. This note was repaid in full on its
maturity date of March 2, 2006.
120
DESCRIPTION
OF SENIOR NOTES
You can find the definitions of certain terms used in this
description under the subheading Certain
Definitions. In this description, the words
Mariner, we, us and
our refers only to Mariner Energy, Inc. and not to
any of its subsidiaries.
On April 24, 2006, we issued $300.0 million aggregate
principal amount of
71/2% Senior
Notes under the indenture dated as of April 24, 2006 among
us and Wells Fargo, N.A., as trustee, and the Guarantors, in a
private transaction not subject to the registration requirements
of the Securities Act. The terms of the old notes and the new
notes include those stated in the indenture and those made part
of the indenture by reference to the Trust Indenture Act of
1939, as amended (the Trust Indenture Act).
The following description is a summary of the material
provisions of the indenture and the registration rights
agreement. It does not restate those agreements in their
entirety. We urge you to read the indenture and the registration
rights agreement because they, and not this description, define
your rights as holders of the notes. Copies of the indenture and
the registration rights agreement are available as set forth
below under Additional Information.
Certain defined terms used in this description but not defined
below under Certain Definitions have the
meanings assigned to them in the indenture.
The registered holder of a note will be treated as the owner of
it for all purposes. Only registered holders will have rights
under the indenture.
Brief
Description of the Notes and the Note Guarantees
The
Notes
The notes are:
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general unsecured obligations of Mariner;
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|
limited to an aggregate principal amount at maturity of
$300 million, subject to our ability to issue additional
notes;
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|
accrue interest from the date they are issued at a rate of
71/2%, which is payable semi-annually;
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mature on April 15, 2013;
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rank effectively junior in right of payment to any secured
Indebtedness of Mariner, including Indebtedness under the Credit
Agreement, to the extent of the value of the Collateral securing
such Indebtedness;
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rank pari passu in right of payment with all existing and
future unsecured senior Indebtedness of Mariner;
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rank senior in right of payment to any future subordinated
Indebtedness of Mariner; and
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fully and unconditionally guaranteed on a senior unsecured basis
by the Guarantors.
|
See Risk Factors The notes and the guarantees
are unsecured and effectively subordinated to our and our
subsidiary guarantors existing and future secured
indebtedness.
The
Note Guarantees
The notes will be guaranteed by all of Mariners presently
existing Domestic Subsidiaries. Each guarantee of the notes is:
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a general unsecured obligation of the Guarantor;
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rank effectively junior in right of payment to any secured
Indebtedness of that Guarantor, including Indebtedness under the
Credit Agreement, to the extent of the value of the Collateral
securing such Indebtedness;
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121
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|
rank pari passu in right of payment with any future
unsecured senior Indebtedness of that Guarantor; and
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|
rank senior in right of payment to any future subordinated
Indebtedness of that Guarantor.
|
Newly created or acquired Restricted Subsidiaries are required
to guarantee the notes only under the circumstances described
below under the caption Certain
Covenants Additional Note Guarantees. In the
event of a bankruptcy, liquidation or reorganization of any
non-guarantor Subsidiary, the non-guarantor Subsidiary will pay
the holders of its debt and its trade creditors before it will
be able to distribute any of its assets to Mariner.
As of the date of the indenture, all of our Subsidiaries were
Restricted Subsidiaries. However, under the
circumstances described below under the caption
Certain Covenants Designation of
Restricted and Unrestricted Subsidiaries, we are permitted
to designate certain of our Subsidiaries as Unrestricted
Subsidiaries. Our Unrestricted Subsidiaries are not
subject to many of the restrictive covenants in the indenture.
Our Unrestricted Subsidiaries will not guarantee the notes.
Principal,
Maturity and Interest
Mariner will issue up to $300 million in aggregate
principal amount of new notes in the exchange offer in exchange
for old notes. Mariner may issue additional notes under the
indenture from time to time after the exchange offer. Any
issuance of additional notes is subject to all of the covenants
in the indenture, including the covenant described below under
the caption Certain Covenants
Incurrence of Indebtedness and Issuance of Preferred
Stock. The notes and any additional notes subsequently
issued under the indenture will be treated as a single class for
all purposes under the indenture, including, without limitation,
waivers, amendments, redemptions and offers to purchase. Notes
will be issued in minimum denominations of $1,000 and integral
multiples of $1,000. The notes will mature on April 15,
2013.
Interest on the notes accrues at the rate of 71/2% per
annum and is payable semi-annually in arrears on April 15 and
October 15, commencing on October 15, 2006. Interest
on overdue principal and interest and Special Interest, if any,
accrues at a rate that is 1.0% higher than the then applicable
interest rate on the notes. Mariner makes each interest payment
to the holders of record on the immediately preceding
April 1 and October 1.
Interest on the notes accrues from the date of original issuance
or, if interest has already been paid, from the date it was most
recently paid. Interest is computed on the basis of a
360-day year
comprised of twelve
30-day
months.
Methods
of Receiving Payments on the Notes
If a holder of notes has given wire transfer instructions to
Mariner, Mariner will pay all principal, interest and premium
and Special Interest, if any, on that holders notes in
accordance with those instructions. All other payments on the
notes will be made at the office or agency of the paying agent
and registrar within the City and State of New York unless
Mariner elects to make interest payments by check mailed to the
noteholders at their address set forth in the register of
holders.
Paying
Agent and Registrar for the Notes
The trustee will initially act as paying agent and registrar.
Mariner may change the paying agent or registrar without prior
notice to the holders of the notes, and Mariner or any of its
Subsidiaries may act as paying agent or registrar.
Transfer
and Exchange
A holder may transfer or exchange notes in accordance with the
provisions of the indenture. The registrar and the trustee may
require a holder, among other things, to furnish appropriate
endorsements and transfer documents in connection with a
transfer of notes. Holders will be required to pay all taxes due
on transfer.
122
Mariner is not required to transfer or exchange any note
selected for redemption. Also, Mariner is not required to
transfer or exchange any note for a period of 15 days
before a selection of notes to be redeemed.
Note
Guarantees
Mariners payment obligations with respect to the notes are
jointly and severally guaranteed on a senior basis by the
Guarantors. Additional Domestic Subsidiaries of Mariner will be
required to become Guarantors under the circumstances described
under Certain Covenants Additional
Subsidiary Guarantees. These Note Guarantees are joint and
several obligations of the Guarantors. The obligations of each
Guarantor under its Note Guarantee are limited as necessary to
prevent that Note Guarantee from constituting a fraudulent
conveyance under applicable law. See Risk
Factors Risks relating to the notes A
subsidiary guarantee could be voided if it constitutes a
fraudulent transfer under U.S. bankruptcy or similar state
law, which would prevent the holders of the notes from relying
on that subsidiary to satisfy claims.
A Guarantor may not sell or otherwise dispose of all or
substantially all of its assets to, or consolidate with or merge
with or into (whether or not such Guarantor is the surviving
Person), another Person, other than Mariner or another
Guarantor, unless:
(1) immediately after giving effect to that transaction, no
Default or Event of Default exists; and
(2) either:
(a) the Person acquiring the property in any such sale or
disposition or the Person formed by or surviving any such
consolidation or merger (if other than Mariner or another
Guarantor) unconditionally assumes, pursuant to a supplemental
indenture substantially in the form specified in the indenture,
all the obligations of such Guarantor under such indenture, such
series of notes, its Note Guarantee and the applicable
registration rights agreement on terms set forth therein; or
(b) the Net Proceeds of such sale or other disposition are
applied in accordance with the provisions of the indenture
described under the caption Repurchase at the
Option of Holders Asset Sales.
The Note Guarantee of a Guarantor will be released:
(1) in connection with any sale or other disposition of all
or substantially all of the assets of that Guarantor (including
by way of merger or consolidation) to a Person that is not
(either before or after giving effect to such transaction)
Mariner or a Restricted Subsidiary of Mariner, if the sale or
other disposition complies with the applicable provisions of the
indenture;
(2) in connection with any sale or other disposition of all
of the Capital Stock of that Guarantor to a Person that is not
(either before or after giving effect to such transaction)
Mariner or a Restricted Subsidiary of Mariner, if the sale or
other disposition complies with the applicable provisions of the
indenture;
(3) if such Guarantor is a Restricted Subsidiary and
Mariner designates such Guarantor as an Unrestricted Subsidiary
in accordance with the applicable provisions of the indenture;
(4) upon Legal Defeasance or Covenant Defeasance as
described below under the caption Legal
Defeasance and Covenant Defeasance or upon satisfaction
and discharge of the indenture as described under the caption
Satisfaction and Discharge;
(5) upon the liquidation or dissolution of such Guarantor
provided no Default or Event of Default has occurred or is
continuing;
(6) at any time after the occurrence of an Investment Grade
Rating Event, at such time as such Guarantor does not have
outstanding or guarantee Indebtedness (other than Indebtedness
or guarantees under the notes) in excess of $5.0 million in
aggregate principal amount; or
123
(7) upon such Guarantor consolidating with, merging into or
transferring all of its properties or assets to Mariner or
another Guarantor, and as a result of, or in connection with,
such transaction such Guarantor dissolving or otherwise ceasing
to exist.
Optional
Redemption
Except as otherwise described below, the notes will not be
redeemable at Mariners option prior to April 15,
2010. Mariner is not, however, prohibited from acquiring the
notes by means other than a redemption, whether pursuant to a
tender offer, open market purchase or otherwise, so long as the
acquisition does not violate the terms of the indenture.
On or after April 15, 2010, the notes will be subject to
redemption at the option of Mariner, in whole or in part, at the
redemption prices (expressed as percentages of principal amount)
set forth below plus accrued and unpaid interest and Special
Interest, if any, thereon to, but not including, the applicable
redemption date, if redeemed during the twelve-month period
beginning on April 15 of the year indicated below:
|
|
|
|
|
|
|
% of Principal
|
|
Year
|
|
Amount
|
|
|
2010
|
|
|
103.750
|
%
|
2011
|
|
|
101.875
|
%
|
2012 and thereafter
|
|
|
100.000
|
%
|
Prior to April 15, 2009, Mariner may, at its option, on any
one or more occasions, redeem up to 35% of the aggregate
principal amount of the notes (including any additional notes
issued after the Issue Date) at a redemption price equal to
107.50% of the principal amount thereof, plus accrued and unpaid
interest and Special Interest, if any, thereon to, but not
including, the redemption date, with all or a portion of the net
proceeds of one or more Equity Offerings; provided that
at least 65% of the aggregate principal amount of the notes
issued under the indenture remains outstanding immediately after
the occurrence of such redemption; and provided, further,
that such redemption shall occur within 180 days of the
date of the closing of any such Equity Offering.
In addition, at any time prior to April 15, 2010 Mariner
may also redeem, in whole or in part, the notes at a redemption
price equal to 100% of the principal amount of notes to be
redeemed, plus the Applicable Premium (as defined below) as of,
and accrued and unpaid interest and Special Interest, if any,
to, but not including, the redemption date, subject to the
rights of the holders on the relevant record date to receive
interest and Special Interest, if any, due on the relevant
interest payment date.
Applicable Premium means, with respect to any
note on any redemption date, the excess of:
(1) the present value at such redemption date of
(i) the redemption price of the note on April 15, 2010
(such redemption price being set forth in the table appearing
above under the caption Optional
redemption), plus (ii) all required interest payments
and Special Interest, if applicable, payments due on the note
through April 15, 2010 (excluding accrued but unpaid
interest and Special Interest, if any, to the redemption date)
discounted back to the redemption date on a semi-annual basis
(assuming a
360-day year
consisting of twelve
30-day
months) at a rate equal to the Treasury Rate as of such
redemption date plus 50 basis points; over
(2) the principal amount of the note.
Treasury Rate means, as of any redemption
date, the yield to maturity as of such redemption date of United
States Treasury securities with a constant maturity (as compiled
and published in the most recent Federal Reserve Statistical
Release H.15 (519) that has become publicly available at
least two Business Days prior to the redemption date (or, if
such Statistical Release is no longer published, any publicly
available source of similar market data)) most nearly equal to
the period from the redemption date to April 15, 2010;
provided, however, that if the period from the redemption date
to April 15, 2010 is less than one year, the weekly average
yield on actually traded United States Treasury securities
adjusted to a constant maturity of one year will be used.
124
All redemptions of the notes will be made upon not less than
30 days nor more than 60 days prior
notice, except that a redemption notice may be made more than
60 days prior to a redemption date if the notice is issued
in connection with a defeasance of the notes or a satisfaction
and discharge of the indenture. Unless Mariner defaults in the
payment of the redemption price, interest and Special Interest,
if applicable, will cease to accrue on the notes or portions
thereof called for redemption on the applicable redemption date.
Notice of any redemption including, without limitation, upon an
Equity Offering may, at Mariners discretion, be subject to
one or more conditions precedent, including, but not limited to,
completion of the related Equity Offering.
Mandatory
Redemption
Except as set forth below under Repurchase at the Option
of Holders, Mariner is not required to make mandatory
redemption or sinking fund payments with respect to the notes.
Repurchase
at the Option of Holders
Change
of Control
If a Change of Control Triggering Event occurs, each holder of
notes will have the right to require Mariner to repurchase all
or any part (equal to $1,000 or an integral multiple of $1,000)
of that holders notes pursuant to an offer
(Change of Control Offer) on the terms set
forth in the indenture. In the Change of Control Offer, Mariner
will offer a payment in cash (the Change of Control
Payment) equal to 101% of the aggregate principal
amount of notes repurchased plus accrued and unpaid interest and
Special Interest, if any, on the notes repurchased to the date
of purchase (the Change of Control Payment
Date), subject to the rights of holders of notes on
the relevant record date to receive interest and Special
Interest, if applicable, due on the relevant interest payment
date. Within 30 days following any Change of Control
Triggering Event, Mariner will mail a notice to each holder
describing the transaction or transactions that constitute the
Change of Control Triggering Event and offering to repurchase
notes on the Change of Control Payment Date specified in the
notice, which date will be no earlier than 30 days and no
later than 60 days from the date such notice is mailed,
pursuant to the procedures required by the indenture and
described in such notice. Mariner will comply with the
requirements of
Rule 14e-1
under the Exchange Act and any other securities laws and
regulations thereunder to the extent those laws and regulations
are applicable in connection with the repurchase of the notes as
a result of a Change of Control Triggering Event. To the extent
that the provisions of any securities laws or regulations
conflict with the Change of Control Triggering Event provisions
of the indenture, Mariner will comply with the applicable
securities laws and regulations and will not be deemed to have
breached its obligations under the Change of Control Triggering
Event provisions of the indenture by virtue of such compliance.
On the Change of Control Payment Date, Mariner will, to the
extent lawful:
(1) accept for payment all notes or portions of notes
properly tendered pursuant to the Change of Control Offer;
(2) deposit with the paying agent an amount equal to the
Change of Control Payment in respect of all notes or portions of
notes properly tendered; and
(3) deliver or cause to be delivered to the trustee the
notes properly accepted together with an officers
certificate stating the aggregate principal amount of notes or
portions of notes being purchased by Mariner.
The paying agent will promptly mail to each holder of notes
properly tendered the Change of Control Payment for such notes
(or, if all the notes are then in global form, make such payment
through the facilities of DTC), and the trustee will promptly
authenticate and mail (or cause to be transferred by book entry)
to each holder a new note equal in principal amount to any
unpurchased portion of the notes surrendered, if any;
provided that each such new note will be in a principal
amount of $1,000 or an integral multiple thereof. Any note so
accepted for payment will cease to accrue interest and Special
Interest, if applicable, on and after the
125
Change of Control Payment Date unless Mariner defaults in making
the Change of Control Payment. Mariner will publicly announce
the results of the Change of Control Offer on or as soon as
practicable after the Change of Control Payment Date.
The provisions described herein that require Mariner to make a
Change of Control Offer following a Change of Control Triggering
Event will be applicable whether or not any other provisions of
the indenture are applicable. Except as described above with
respect to a Change of Control Triggering Event, the indenture
does not contain provisions that permit the holders of the notes
to require that Mariner repurchase or redeem the notes in the
event of a takeover, recapitalization or similar transaction.
Mariner will not be required to make a Change of Control Offer
upon a Change of Control Triggering Event if (1) a third
party makes the Change of Control Offer in the manner, at the
times and otherwise in compliance with the requirements set
forth in the indenture applicable to a Change of Control Offer
made by Mariner and purchases all notes properly tendered and
not withdrawn under the Change of Control Offer, or
(2) notice of redemption has been given pursuant to the
indenture as described above under the caption
Optional Redemption, unless and until
there is a default in payment of the applicable redemption price.
A Change of Control Offer may be made in advance of a Change of
Control Triggering Event, and conditioned upon the occurrence of
such Change of Control Triggering Event, if a definitive
agreement is in place for the Change of Control Triggering Event
at the time of making the Change of Control Offer. Notes
repurchased by Mariner pursuant to a Change of Control Offer
will have the status of notes issued but not outstanding or will
be retired and cancelled, at Mariners option. Notes
purchased by a third party pursuant to the preceding paragraph
will have the status of notes issued and outstanding.
The Credit Agreement will prohibit Mariner from repurchasing any
notes pursuant to a Change of Control Offer prior to the
repayment in full of the Indebtedness under the Credit
Agreement. Moreover, the occurrence of certain change of control
events identified in the Credit Agreement constitutes a default
under the Credit Agreement. Any future Credit Facilities or
other agreements relating to the Indebtedness to which Mariner
becomes a party may contain similar restrictions and provisions.
If a Change of Control Triggering Event were to occur, Mariner
may not have sufficient available funds to pay the Change of
Control Payment for all notes that might be delivered by holders
of notes seeking to accept the Change of Control Offer after
first satisfying its obligations under the Credit Agreement or
other agreements relating to Indebtedness, if accelerated. The
failure of Mariner to make or consummate the Change of Control
Offer or pay the Change of Control Payment when due will
constitute a Default under the indenture and will otherwise give
the trustee and the holders of notes the rights described under
Events of default and remedies. See
Risk Factors Risks Relating to the
notes We may not be able to repurchase the notes
upon a change of control.
The definition of Change of Control Triggering Event includes a
phrase relating to the direct or indirect sale, lease, transfer,
conveyance or other disposition of all or substantially
all of the properties or assets of Mariner and its
Subsidiaries taken as a whole. Although there is a limited body
of case law interpreting the phrase substantially
all, there is no precise established definition of the
phrase under applicable law. Accordingly, the ability of a
holder of notes to require Mariner to repurchase its notes as a
result of a sale, lease, transfer, conveyance or other
disposition of less than all of the assets of Mariner and its
Subsidiaries taken as a whole to another Person or group may be
uncertain.
In the event that holders of not less than 90% of the aggregate
principal amount of the outstanding notes accept a Change of
Control Offer and Mariner purchases all of the notes held by
such holders, Mariner will have the right, upon not less than 30
nor more than 60 days prior notice, given not more
than 30 days following the purchase pursuant to the Change
of Control Offer described above, to redeem all of the notes
that remain outstanding following such purchase at a purchase
price equal to the Change of Control Payment plus, to the extent
not included in the Change of Control Payment, accrued and
unpaid interest and Special Interest, if any, on the notes that
remain outstanding, to the date of redemption (subject to the
right of holders on the relevant record date to receive interest
due on the relevant interest payment date).
126
Asset
Sales
Mariner will not, and will not permit any of its Restricted
Subsidiaries to, consummate an Asset Sale unless:
(1) Mariner (or the Restricted Subsidiary, as the case may
be) receives consideration at the time of the Asset Sale at
least equal to the Fair Market Value of the assets or Equity
Interests issued or sold or otherwise disposed of; and
(2) (a) at least 75% of the consideration received in
the Asset Sale by Mariner or such Restricted Subsidiary is in
the form of cash or (b) the Fair Market Value of all forms
of consideration other than cash received for all Asset Sales
since the Issue Date does not exceed in the aggregate 10% of the
Adjusted Consolidated Net Tangible Assets of Mariner at the time
each determination is made. For purposes of this provision, each
of the following will be deemed to be cash:
(a) any liabilities, as shown on Mariners most recent
consolidated balance sheet, of Mariner or any Restricted
Subsidiary (other than contingent liabilities and liabilities
that are by their terms subordinated to the notes or any Note
Guarantee) that are assumed by the transferee of any such assets
pursuant to a customary novation agreement that releases Mariner
or such Restricted Subsidiary from further liability;
(b) any securities, notes or other obligations received by
Mariner or any such Restricted Subsidiary from such transferee
that are converted by Mariner or such Restricted Subsidiary into
cash within 180 days after the date of the Asset Sale, to
the extent of the cash received in that conversion;
(c) any stock or assets of the kind referred to in
clauses (2) or (4) of the next paragraph of this
covenant; and
(d) accounts receivable of a business retained by Mariner
or any Restricted Subsidiary, as the case may be, following the
sale of such business, provided, that such accounts receivable
are not (a) past due more than 90 days and (b) do
not have a payment date greater than 120 days from the date
of the invoice creating such accounts receivable.
Within 360 days after the receipt of any Net Proceeds from
an Asset Sale, Mariner (or the applicable Restricted Subsidiary,
as the case may be) may apply such Net Proceeds:
(1) to repay Senior Debt;
(2) to invest in Additional Assets;
(3) to make capital expenditures in respect of
Mariners or its Restricted Subsidiaries Oil and Gas
Business; or
(4) enter into a bona fide binding contract with a Person
other than an Affiliate of Mariner to apply the Net Proceeds
pursuant to clauses (2) or (3) above, provided that
such binding contract shall be treated as a permitted
application of the Net Proceeds from the date of such contract
until the earlier of (a) the date on which such acquisition
or expenditure is consummated, and (b) the 180th day
following the expiration of the aforementioned
360-day
period.
Pending the final application of any Net Proceeds, Mariner or
any Restricted Subsidiary may temporarily reduce revolving
credit borrowings or otherwise invest the Net Proceeds in any
manner that is not prohibited by the indenture. Any Net Proceeds
from Asset Sales that are not applied or invested as provided in
the second paragraph of this covenant will constitute
Excess Proceeds.
On the 361st day after the Asset Sale (or, at
Mariners option, any earlier date), if the aggregate
amount of Excess Proceeds then exceeds $20.0 million,
Mariner will make an offer (the Asset Sale
Offer) to all holders of notes and all holders of
other Indebtedness that is pari passu with the notes
containing provisions similar to those set forth in the
indenture with respect to offers to purchase or redeem with the
proceeds of sales of assets, to purchase the maximum principal
amount of notes and such other pari passu Indebtedness
127
that may be purchased out of the Excess Proceeds. The offer
price in any Asset Sale Offer will be equal to 100% of the
principal amount plus accrued and unpaid interest and Special
Interest, if any, to the date of purchase, and will be payable
in cash. If any Excess Proceeds remain after consummation of an
Asset Sale Offer, Mariner may use those Excess Proceeds for any
purpose not otherwise prohibited by the indenture. If the
aggregate principal amount of notes and other pari passu
Indebtedness tendered into such Asset Sale Offer exceeds the
amount of Excess Proceeds, the trustee will select the notes to
be purchased on a pro rata basis. Upon completion of each
Asset Sale Offer, the amount of Excess Proceeds will be reset at
zero.
Mariner will comply with the requirements of
Rule 14e-1
under the Exchange Act and any other securities laws and
regulations thereunder to the extent those laws and regulations
are applicable in connection with each repurchase of notes
pursuant to an Asset Sale Offer. To the extent that the
provisions of any securities laws or regulations conflict with
the Asset Sale provisions of the indenture, Mariner will comply
with the applicable securities laws and regulations and will not
be deemed to have breached its obligations under the Asset Sale
provisions of the indenture by virtue of such compliance.
The Credit Agreement and certain other agreements governing
Mariners other Indebtedness contain, and future agreements
may contain, prohibitions of certain events, including events
that would constitute a Change of Control Triggering Event or an
Asset Sale and including repurchases of or other prepayments in
respect of the notes. The exercise by the holders of notes of
their right to require Mariner to repurchase the notes upon a
Change of Control Triggering Event or an Asset Sale could cause
a default under these other agreements, even if the Change of
Control Triggering Event or Asset Sale itself does not due to
the financial effect of such repurchases on Mariner or
otherwise. In the event a Change of Control or Asset Sale occurs
at a time when Mariner is prohibited from purchasing notes,
Mariner could seek the consent of the applicable lenders to the
purchase of notes or could attempt to refinance the Indebtedness
that contain such prohibitions. If Mariner does not obtain a
consent or repay that Indebtedness, Mariner will remain
prohibited from purchasing notes. In that case, Mariners
failure to purchase tendered notes would constitute an Event of
Default under the indenture which could, in turn, constitute a
default under other Indebtedness. Finally, Mariners
ability to pay cash to the holders of notes upon a repurchase
may be limited by Mariners then existing financial
resources. See Risk Factors Risks Relating to
the Notes We may not be able to repurchase the notes
upon a change of control.
Selection
and Notice
If less than all of the notes are to be redeemed at any time,
the trustee will select notes for redemption on a pro rata basis
unless otherwise required by law or applicable stock exchange
requirements.
No notes of $1,000 or less can be redeemed in part. Notices of
redemption will be mailed by first class mail at least 30 but
not more than 60 days before the redemption date to each
holder of notes to be redeemed at its registered address, except
that redemption notices may be mailed more than 60 days
prior to a redemption date if the notice is issued in connection
with a defeasance of the notes or a satisfaction and discharge
of the indenture.
If any note is to be redeemed in part only, the notice of
redemption that relates to that note will state the portion of
the principal amount of that note that is to be redeemed. A new
note in principal amount equal to the unredeemed portion of the
original note will be issued in the name of the holder of notes
upon cancellation of the original note. notes called for
redemption become due on the date fixed for redemption. Notes
called for redemption become due on the date fixed for
redemption except as described in Optional
Redemption. On and after the redemption date, interest and
Special Interest, if any, cease to accrue on notes or portions
of notes called for redemption, unless Mariner defaults in
making the payment of funds for such a redemption.
128
Certain
Covenants
Restricted
Payments
Mariner will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly:
(1) declare or pay any dividend or make any other payment
or distribution on account of Mariners or any of its
Restricted Subsidiaries Equity Interests (including,
without limitation, any such payment or distribution made in
connection with any merger or consolidation involving Mariner or
any of its Restricted Subsidiaries) or to the direct or indirect
holders of Mariners or any of its Restricted
Subsidiaries Equity Interests in their capacity as such
(other than dividends or distributions payable in Equity
Interests (other than Disqualified Stock) of Mariner and other
than dividends or distributions payable to Mariner or a
Restricted Subsidiary of Mariner);
(2) purchase, redeem or otherwise acquire or retire for
value (including, without limitation, any such purchase,
redemption, acquisition or retirement made in connection with
any merger or consolidation involving Mariner) any Equity
Interests of Mariner or any direct or indirect parent or other
Affiliate of Mariner that is not a Restricted Subsidiary of
Mariner;
(3) make any payment on or with respect to, or purchase,
redeem, defease or otherwise acquire or retire for value, prior
to the Stated Maturity thereof, any Indebtedness of Mariner or
any Guarantor that is contractually subordinated to the notes or
to any Note Guarantee (excluding (a) any intercompany
Indebtedness between or among Mariner and any of its Restricted
Subsidiaries or (b) the purchase, repurchase or other
acquisition of Indebtedness that is subordinated to the notes or
the Note Guarantees purchased in anticipation of satisfying a
sinking fund obligation, principal installment or final
maturity, in each case due within one year of the date of
purchase, repurchase or acquisition); or
(4) make any Restricted Investment;
(all such payments and other actions set forth in
clauses (1) through (4) above being collectively
referred to as Restricted Payments),
unless, at the time of and after giving effect to such
Restricted Payment:
(1) no Default or Event of Default has occurred and is
continuing or would occur as a consequence of such Restricted
Payment;
(2) Mariner would, at the time of such Restricted Payment
and after giving pro forma effect thereto as if such Restricted
Payment had been made at the beginning of the applicable
four-quarter period, have been permitted to incur at least $1.00
of additional Indebtedness pursuant to the Fixed Charge Coverage
Ratio test set forth in the first paragraph of the covenant
described below under the caption Incurrence
of Indebtedness and Issuance of Preferred Stock; and
(3) such Restricted Payment, together with the aggregate
amount of all other Restricted Payments made by Mariner and its
Restricted Subsidiaries since the date of the indenture
(excluding Restricted Payments permitted by clauses (2), (3),
(4), (5), (6), (7), (8) and (10) of the next
succeeding paragraph), is equal to or less than the sum, without
duplication, of:
(a) 50% of the Consolidated Net Income of Mariner for the
period (taken as one accounting period) from the beginning of
the first fiscal quarter commencing after the Issue Date to the
end of Mariners most recently ended fiscal quarter for
which internal financial statements are available at the time of
such Restricted Payment (or, if such Consolidated Net Income for
such period is a deficit, less 100% of such deficit); plus
(b) 100% of the aggregate net cash proceeds received, and
the Fair Market Value of property received from a non-Affiliate
used or useful in an Oil and Gas Business, by Mariner since the
Issue Date as a contribution to its common capital or from the
issue or sale of Equity Interests of Mariner (other than
Disqualified Stock) or from the issue or sale of convertible or
exchangeable Disqualified Stock or convertible or exchangeable
debt securities of Mariner that have been converted into or
129
exchanged for such Equity Interests (other than Equity Interests
(or Disqualified Stock or debt securities) sold to a Subsidiary
of Mariner or an employee stock ownership plan, option plan or
similar trust to the extent such sale to an employee stock
ownership plan, option plan or similar trust is financed by
loans from or guaranteed by Mariner or any of its Restricted
Subsidiaries unless such loans have been repaid with cash on or
prior to the date of determination); plus
(c) the amount equal to the net reduction in Restricted
Investments made by Mariner or any of its Restricted
Subsidiaries in any Person resulting from:
(i) repurchases or redemptions of such Restricted
Investments by such Person, proceeds realized upon the sale of
such Restricted Investment to a purchaser other than Mariner or
a Subsidiary or Mariner, repayments of loans or advances or
other transfers of assets (including by way of dividend or
distribution) by such Person to Mariner or any Restricted
Subsidiary of Mariner; or
(ii) the redesignation of Unrestricted Subsidiaries as
Restricted Subsidiaries (valued in each case as provided in the
definition of Investment) not to exceed, in the case
of any Unrestricted Subsidiary, the amount of Investments
previously made by Mariner or any Restricted Subsidiary of
Mariner in such Unrestricted Subsidiary, which amount in each
case under this clause (c) was included in the calculation
of the amount of Restricted Payments; provided, however, that no
amount will be included under this clause (c) to the extent
it is already included in Consolidated Net Income; plus
(d) 50% of any dividends received by Mariner or a
Restricted Subsidiary of Mariner that is a Guarantor after the
Issue Date from an Unrestricted Subsidiary of Mariner, to the
extent that such dividends were not otherwise included in the
Consolidated Net Income of Mariner for such period.
So long as no Default has occurred and is continuing or would be
caused thereby, the preceding provisions will not prohibit:
(1) the payment of any dividend or the consummation of any
irrevocable redemption within 60 days after the date of
declaration of the dividend or giving of the redemption notice,
as the case may be, if at the date of declaration or notice, the
dividend or redemption payment would have complied with the
provisions of the indenture;
(2) the making of any Restricted Payment in exchange for,
or out of the net cash proceeds of the substantially concurrent
sale (other than to a Subsidiary of Mariner) of, Equity
Interests of Mariner (other than Disqualified Stock and other
than Equity Interests issued or sold to an employee stock
ownership plan, option plan or similar trust to the extent such
sale to an employee stock ownership plan, option plan or similar
trust is financed by loans from or guaranteed by Mariner or any
of its Restricted Subsidiaries unless such loans have been
repaid with cash on or prior to the date of determination) or
from the substantially concurrent contribution of common equity
capital to Mariner; provided that the amount of any such
net cash proceeds that are utilized for any such Restricted
Payment will be excluded from clause (3)(b) of the
preceding paragraph;
(3) the repurchase, redemption, defeasance or other
acquisition or retirement for value of Indebtedness of Mariner
or any Guarantor that is contractually subordinated to the notes
or to any Note Guarantee with the net cash proceeds from a
substantially concurrent incurrence of Permitted Refinancing
Indebtedness;
(4) the payment of any dividend (or, in the case of any
partnership or limited liability company, any similar
distribution) by a Restricted Subsidiary of Mariner to the
holders of its Equity Interests on a pro rata basis;
(5) the defeasance, repurchase, redemption or other
acquisition or retirement for value of any Equity Interests of
Mariner or any Restricted Subsidiary of Mariner held by any of
Mariners (or any of its Restricted Subsidiaries)
current or former directors or employees pursuant to any
director or employee equity subscription agreement, stock option
agreement or restricted stock agreement; provided that
the
130
aggregate price paid for all such repurchased, redeemed,
acquired or retired Equity Interests may not exceed
$3.0 million in any twelve-month period (with unused
amounts in any
12-month
period being permitted to be carried over into succeeding
12-month
periods); provided, further, that the amounts in any
12-month
period may be increased by an amount not to exceed (A) the
cash proceeds received by Mariner or any of its Restricted
Subsidiaries from the sale of Mariners Equity Interests
(other than Disqualified Stock) to any such directors or
employees that occurs after the Issue Date (provided that
the amount of such cash proceeds utilized for any such
repurchase, retirement or other acquisition or retirement will
not increase the amount available for Restricted Payments under
clause (3) of the immediately preceding paragraph and to
the extent such proceeds have not otherwise been applied to the
payment of Restricted Payments) plus (B) the cash proceeds
of key man life insurance policies received by Mariner and its
Restricted Subsidiaries after the Issue Date;
(6) the defeasance, repurchase, redemption or other
acquisition or retirement for value of any Equity Interests of
Mariner or any Restricted Subsidiary of Mariner held by any of
Mariners (or any of its Restricted Subsidiaries)
current or former directors or employees in connection with the
exercise or vesting of any equity compensation (including,
without limitation, stock options, restricted stock and phantom
stock) in order to satisfy Mariners or such Restricted
Subsidiarys tax withholding obligation with respect to
such exercise or vesting;
(7) any payments made in connection with the consummation
of the transaction closing contemporaneously with the closing of
the offering of old notes;
(8) so long as no Default has occurred and is continuing or
would be caused thereby, repurchases of Indebtedness that is
subordinated to the notes or a Note Guarantee at a purchase
price not greater than (i) 101% of the principal amount of
such subordinated Indebtedness and accrued and unpaid interest
thereon in the event of a Change of Control Triggering Event or
(ii) 100% of the principal amount of such subordinated
Indebtedness and accrued and unpaid interest thereon in the
event of an Asset Sale, in each case plus accrued interest, in
connection with any change of control offer or asset sale offer
required by the terms of such Indebtedness, but only if:
(a) in the case of a Change of Control Triggering Event,
Mariner has first complied with and fully satisfied its
obligations under the provisions described under
Repurchase at the Option of
Holders Change of Control Triggering
Event; or
(b) in the case of an Asset Sale, Mariner has complied with
and fully satisfied its obligations in accordance with the
covenant under the heading, Repurchase at the
Option of Holders Asset Sales;
(9) the repurchase, redemption or other acquisition for
value of Capital Stock of Mariner representing fractional shares
of such Capital Stock in connection with a merger,
consolidation, amalgamation or other combination involving
Mariner or any other transaction permitted by the indenture;
(10) repurchases of Capital Stock deemed to occur upon the
exercise of stock options if such Capital Stock represents a
portion of the exercise price thereof;
(11) the declaration and payment of regularly scheduled or
accrued dividends to holders of any class or series of
Disqualified Stock of Mariner or any Restricted Subsidiary of
Mariner issued on or after the Issue Date in accordance with the
Fixed Charge Coverage Ratio test described below under the
caption Incurrence of Indebtedness and
Issuance of Preferred Stock; and
(12) other Restricted Payments in an aggregate amount not
to exceed $25.0 million since the Issue Date.
The amount of all Restricted Payments (other than cash) will be
the Fair Market Value on the date of the Restricted Payment of
the asset(s) or securities proposed to be transferred or issued
by Mariner or such Restricted Subsidiary, as the case may be,
pursuant to the Restricted Payment. The Fair Market Value of any
assets or securities that are required to be valued by this
covenant will be determined by the Board of
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Directors of Mariner whose resolution with respect thereto will
be delivered to the trustee. For purposes of determining
compliance with this covenant, in the event that a Restricted
Payment meets the criteria of more than one of the exceptions
described in (1) through (12) above or is entitled to
be made pursuant to the first paragraph of this covenant,
Mariner shall, in its sole discretion, classify such Restricted
Payment, or later classify, reclassify or re-divide all or a
portion of such Restricted Payment, in any manner that complies
with this covenant.
Incurrence
of Indebtedness and Issuance of Preferred Stock
Mariner will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, incur, issue,
assume, guarantee or otherwise become directly or indirectly
liable, contingently or otherwise, with respect to
(collectively, incur) any Indebtedness
(including Acquired Debt), and Mariner will not issue any
Disqualified Stock and will not permit any of its Restricted
Subsidiaries to issue any shares of preferred stock;
provided, however, that Mariner and the Restricted
Subsidiaries may incur Indebtedness (including Acquired Debt) or
issue Disqualified Stock, if the Fixed Charge Coverage Ratio for
Mariners most recently ended four full fiscal quarters for
which internal financial statements are available immediately
preceding the date on which such additional Indebtedness is
incurred or such Disqualified Stock is issued, as the case may
be, would have been at least 2.25 to 1.0, determined on a pro
forma basis (including a pro forma application of the net
proceeds therefrom), as if the additional Indebtedness had been
incurred or the Disqualified Stock had been issued, as the case
may be, at the beginning of such four-quarter period.
The first paragraph of this covenant will not prohibit the
incurrence of any of the following items of Indebtedness
(collectively, Permitted Debt):
(1) the incurrence by Mariner and any Restricted Subsidiary
of additional Indebtedness and letters of credit under Credit
Facilities in an aggregate principal amount at any one time
outstanding under this clause (1) (with letters of credit
being deemed to have a principal amount equal to the maximum
potential liability of Mariner and its Restricted Subsidiaries
thereunder) not to exceed the greater of
(a) $600.0 million and (b) an amount equal to the
sum of (A) $300.0 million plus (B) 10% of
Adjusted Consolidated Net Tangible Assets determined as of the
date of the incurrence of such Indebtedness after giving pro
forma effect to such incurrence and the application of the
proceeds therefrom;
(2) the incurrence by Mariner and its Restricted
Subsidiaries of the Existing Indebtedness;
(3) the incurrence by Mariner and the Guarantors of
Indebtedness represented by the notes and the related Note
Guarantees to be issued on the date of the indenture and the
notes and the related Note Guarantees to be issued pursuant to
the registration rights agreement;
(4) the incurrence by Mariner or any of its Restricted
Subsidiaries of Indebtedness represented by Capital Lease
Obligations, mortgage financings or purchase money obligations,
in each case, incurred for the purpose of financing all or any
part of the purchase price or cost of design, construction,
installation or improvement of property, plant or equipment used
in the business of Mariner or any of its Restricted
Subsidiaries, in an aggregate principal amount, including all
Permitted Refinancing Indebtedness incurred to renew, refund,
refinance, replace, defease or discharge any Indebtedness
incurred pursuant to this clause (4), not to exceed
$50.0 million at any time outstanding;
(5) the incurrence by Mariner or any of its Restricted
Subsidiaries of Permitted Refinancing Indebtedness in exchange
for, or the net proceeds of which are used to renew, refund,
refinance, replace, defease or discharge any Indebtedness (other
than intercompany Indebtedness) that was permitted by the
indenture to be incurred under the first paragraph of this
covenant or clauses (2), (3), (4) or (11) of this
paragraph or this clause (5);
(6) the incurrence by Mariner or any of its Restricted
Subsidiaries of intercompany Indebtedness between or among
Mariner and any of its Restricted Subsidiaries; provided,
however, that:
(a) if Mariner or any Guarantor is the obligor on such
Indebtedness and the payee is not Mariner or a Guarantor, such
Indebtedness must be expressly subordinated to the prior payment
in
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full in cash of all Obligations then due with respect to the
notes, in the case of Mariner, or the Note Guarantee, in the
case of a Guarantor; and
(b) (i) any subsequent issuance or transfer of Equity
Interests that results in any such Indebtedness being held by a
Person other than Mariner or a Restricted Subsidiary of Mariner
and (ii) any sale or other transfer of any such
Indebtedness to a Person that is not either Mariner or a
Restricted Subsidiary of Mariner will be deemed, in each case,
to constitute an incurrence of such Indebtedness by Mariner or
such Restricted Subsidiary, as the case may be, that was not
permitted by this clause (6);
(7) the issuance by any of Mariners Restricted
Subsidiaries to Mariner or to any of its Restricted Subsidiaries
of shares of preferred stock; provided, however, that:
(a) any subsequent issuance or transfer of Equity Interests
that results in any such preferred stock being held by a Person
other than Mariner or a Restricted Subsidiary of
Mariner; and
(b) any sale or other transfer of any such preferred stock
to a Person that is not either Mariner or a Restricted
Subsidiary of Mariner, will be deemed, in each case, to
constitute an issuance of such preferred stock by such
Restricted Subsidiary that was not permitted by this
clause (7);
(8) the incurrence by Mariner or any of its Restricted
Subsidiaries of Hedging Obligations in the ordinary course of
business;
(9) the incurrence by Mariner of any of its Restricted
Subsidiaries of obligations relating to net gas balancing
positions arising in the ordinary course of business and
consistent with past practice;
(10) the guarantee by Mariner or any of the Guarantors of
Indebtedness of Mariner or a Restricted Subsidiary of Mariner
that was permitted to be incurred by another provision of this
covenant; provided that if the Indebtedness being
guaranteed is subordinated to or pari passu with the
notes, then the guarantee shall be subordinated or pari
passu, as applicable, to the same extent as the Indebtedness
guaranteed;
(11) Permitted Acquisition Indebtedness;
(12) the incurrence by Mariner or any of its Restricted
Subsidiaries of Indebtedness arising from the honoring by a bank
or other financial institution of a check, draft or similar
instrument inadvertently drawn against insufficient funds, so
long as such Indebtedness is covered within five Business Days;
(13) Indebtedness consisting of the financing of insurance
premiums in customary amounts consistent with the operations and
business of Mariner and its Restricted Subsidiaries;
(14) the incurrence by Mariner or any of its Restricted
Subsidiaries of Indebtedness arising from agreements of Mariner
or any of its Restricted Subsidiaries providing for
indemnification, adjustment of purchase price or similar
obligations, in each case, incurred or assumed in connection
with the disposition of any business, assets or Capital Stock of
a Subsidiary, provided that the maximum aggregate liability in
respect of all such Indebtedness shall at no time exceed the
gross proceeds actually received by Mariner and its Restricted
Subsidiaries in connection with such disposition;
(15) the incurrence by Mariner or any of its Restricted
Subsidiaries of Indebtedness in respect of bid, performance,
surety and similar bonds issued for the account of Mariner and
any of its Restricted Subsidiaries in the ordinary course of
business, including guarantees and obligations of Mariner or any
of its Restricted Subsidiaries with respect to letters of credit
supporting such obligations (in each case, other than an
obligation for money borrowed);
(16) the incurrence by Mariner or any of its Restricted
Subsidiaries of Indebtedness arising from guarantees of
Indebtedness of joint ventures at any time outstanding not to
exceed the greater of $10.0 million and 1.00% of the
Adjusted Consolidated Net Tangible Assets determined as of the
date of the incurrence of such Indebtedness after giving pro
forma effect to such incurrence and the application of proceeds
therefrom; and
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(17) the incurrence by Mariner or any of its Restricted
Subsidiaries of additional Indebtedness in an aggregate
principal amount (or accreted value, as applicable) at any time
outstanding not to exceed the greater of $50.0 million and
2.50% of the Adjusted Consolidated Net Tangible Assets
determined as of the date of the incurrence of such Indebtedness
after giving pro forma effect to such incurrence and the
application of proceeds therefrom.
Mariner will not incur, and will not permit any Guarantor to
incur, any Indebtedness (including Permitted Debt) that is
contractually subordinated in right of payment to any other
Indebtedness of Mariner or such Guarantor unless such
Indebtedness is also contractually subordinated in right of
payment to the notes and the applicable Note Guarantee on
substantially identical terms; provided, however, that no
Indebtedness will be deemed to be contractually subordinated in
right of payment to any other Indebtedness of Mariner solely by
virtue of being unsecured or by virtue of being secured on a
first or junior Lien basis.
For purposes of determining compliance with this
Incurrence of Indebtedness and Issuance of Preferred
Stock covenant, in the event that an item of proposed
Indebtedness meets the criteria of more than one of the
categories of Permitted Debt described in clauses (1)
through (17) above, or is entitled to be incurred pursuant
to the first paragraph of this covenant, Mariner will be
permitted to classify such item of Indebtedness on the date of
its incurrence, or later reclassify all or a portion of such
item of Indebtedness, in any manner that complies with this
covenant. The accrual of interest, the accretion or amortization
of original issue discount, the payment of interest on any
Indebtedness in the form of additional Indebtedness with the
same terms, the reclassification of preferred stock as
Indebtedness due to a change in accounting principles, and the
payment of dividends on Disqualified Stock in the form of
additional shares of the same class of Disqualified Stock will
not be deemed to be an incurrence of Indebtedness or an issuance
of Disqualified Stock for purposes of this covenant;
provided, in each such case, that the amount of any such
accrual, accretion or payment is included in Fixed Charges of
Mariner as accrued. Notwithstanding any other provision of this
covenant, the maximum amount of Indebtedness that Mariner or any
Restricted Subsidiary may incur pursuant to this covenant shall
not be deemed to be exceeded solely as a result of fluctuations
in exchange rates or currency values.
Liens
Mariner will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, incur, assume
or suffer to exist any Lien of any kind (other than Permitted
Liens) upon any of its property or assets (whether now owned or
hereafter acquired), securing any Subordinated Obligations or
Indebtedness, unless:
(1) in the case of any Lien securing Subordinated
Obligations of Mariner or a Guarantor, the notes or Note
Guarantee, as applicable, are secured by a Lien on such property
or assets on a senior basis to the Subordinated Obligations so
secured until such time as such Subordinated Obligations are no
longer so secured by that Lien; and
(2) in the case of any other Lien (other than a Permitted
Lien) securing Indebtedness, the notes or note Guarantees, as
applicable, are secured by a Lien on such property or assets on
an equal and ratable basis with the Senior Debt so secured until
such time as such Senior Debt is no longer so secured by that
Lien.
Dividend
and Other Payment Restrictions Affecting
Subsidiaries
Mariner will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create or permit to
exist or become effective any consensual encumbrance or
restriction on the ability of any Restricted Subsidiary to:
(1) pay dividends or make any other distributions on its
Capital Stock to Mariner or any of its Restricted Subsidiaries,
or with respect to any other interest or participation in, or
measured by, its profits, or pay any indebtedness owed to
Mariner or any of its Restricted Subsidiaries;
(2) make loans or advances to Mariner or any of its
Restricted Subsidiaries; or
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(3) sell, lease or transfer any of its properties or assets
to Mariner or any of its Restricted Subsidiaries.
However, the preceding restrictions will not apply to
encumbrances or restrictions existing under or by reason of:
(1) agreements governing Existing Indebtedness and Credit
Facilities as in effect on the Issue Date and any amendments,
restatements, modifications, renewals, supplements, increases,
refundings, replacements or refinancings of those agreements;
provided that the amendments, restatements,
modifications, renewals, supplements, increases, refundings,
replacements or refinancings are no more restrictive, taken as a
whole, with respect to such dividend and other payment
restrictions than those contained in those agreements on the
Issue Date;
(2) the indenture, the notes and the Note Guarantees;
(3) applicable law, rule, regulation, order, approval,
permit or similar restriction;
(4) any instrument governing Indebtedness or Capital Stock
of a Person acquired by Mariner or any of its Restricted
Subsidiaries as in effect at the time of such acquisition
(except to the extent such Indebtedness or Capital Stock was
incurred in connection with or in contemplation of such
acquisition), which encumbrance or restriction is not applicable
to any Person, or the properties or assets of any Person, other
than the Person, or the property or assets of the Person, so
acquired; provided that, in the case of Indebtedness,
such Indebtedness was permitted by the terms of the indenture to
be incurred;
(5) customary non-assignment provisions in contracts,
leases and licenses (including, without limitation, licenses of
intellectual property) entered into in the ordinary course of
business;
(6) purchase money obligations for property (including
Capital Stock) acquired in the ordinary course of business,
Capital Lease Obligations and mortgage financings that impose
restrictions on the property purchased or leased of the nature
described in clause (3) of the preceding paragraph;
(7) any agreement for the sale or other disposition of
assets, including without limitation an agreement for the sale
or other disposition of the Capital Stock or assets of a
Restricted Subsidiary, that restricts distributions by the
applicable Restricted Subsidiary pending the sale or other
disposition;
(8) Permitted Refinancing Indebtedness; provided
that the restrictions contained in the agreements governing
such Permitted Refinancing Indebtedness are not materially more
restrictive, taken as a whole, than those contained in the
agreements governing the Indebtedness being refinanced;
(9) Liens permitted to be incurred under the provisions of
the covenant described above under the caption
Liens that limit the right of the debtor
to dispose of the assets subject to such Liens;
(10) provisions limiting the disposition or distribution of
assets or property in, or transfer of Capital Stock of, joint
venture agreements, asset sale agreements, sale-leaseback
agreements, stock sale agreements and other similar agreements
entered into (a) in the ordinary course of business,
consistent with past practice or (b) with the approval of
Mariners Board of Directors, which limitations are
applicable only to the assets, property or Capital Stock that
are the subject of such agreements;
(11) other Indebtedness of Mariner or any of its Restricted
Subsidiaries permitted to be incurred pursuant to an agreement
entered into subsequent to the Issue Date in accordance with the
covenant described under the caption
Incurrence of Indebtedness and Issuance of
Preferred Stock; provided that the provisions
relating to such encumbrance or restriction contained in such
Indebtedness are not materially less favorable to Mariner taken
as a whole, as determined by the Board of Directors of Mariner
in good faith, than the provisions contained in the Credit
Agreement and in the indenture as in effect on the Issue Date;
(12) the issuance of preferred stock by a Restricted
Subsidiary or the payment of dividends thereon in accordance
with the terms thereof; provided that issuance of such
preferred stock is permitted pursuant to the covenant described
under the caption Incurrence of Indebtedness
and Issuance of Preferred
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Stock and the terms of such preferred stock do not
expressly restrict the ability of a Restricted Subsidiary to pay
dividends or make any other distributions on its Capital Stock
(other than requirements to pay dividends or liquidation
preferences on such preferred stock prior to paying any
dividends or making any other distributions on such other
Capital Stock);
(13) supermajority voting requirements existing under
corporate charters, bylaws, stockholders agreements and similar
documents and agreements;
(14) customary provisions restricting subletting or
assignment of any lease governing a leasehold interest;
(15) encumbrances or restrictions contained in Hedging
Obligations permitted from time to time under the
indenture; and
(16) restrictions on cash or other deposits or net worth
imposed by customers under contracts entered into in the
ordinary course of business.
Merger,
Consolidation or Sale of Assets
Mariner will not, directly or indirectly, consolidate,
amalgamate or merge with or into another Person (whether or not
Mariner is the surviving corporation), convert into another form
of entity or continue in another jurisdiction; or sell, assign,
transfer, lease, convey or otherwise dispose of all or
substantially all of its properties or assets, in one or more
related transactions, to another Person, unless:
(1) either: (a) Mariner is the surviving corporation;
or (b) the Person formed by or surviving any such
consolidation, amalgamation or merger or resulting from such
conversion (if other than Mariner) or to which such sale,
assignment, transfer, conveyance or other disposition has been
made is a corporation, limited liability company or limited
partnership organized or existing under the laws of the United
States, any state of the United States or the District of
Columbia;
(2) the Person formed by or surviving any such conversion,
consolidation, amalgamation or merger (if other than Mariner) or
the Person to which such sale, assignment, transfer, conveyance
or other disposition has been made assumes all the obligations
of Mariner under the notes, the indenture and the registration
rights agreement pursuant to agreements reasonably satisfactory
to the trustee; provided that, unless such Person is a
corporation, a corporate co-issuer of the notes will be added to
the indenture by agreements reasonably satisfactory to the
trustee;
(3) immediately after such transaction or transactions, no
Default or Event of Default exists; and
(4) Mariner or the Person formed by or surviving any such
consolidation, amalgamation or merger (if other than Mariner),
or to which such sale, assignment, transfer, conveyance or other
disposition has been made:
(a) would have Consolidated Net Worth immediately after the
transaction equal to or greater than the Consolidated Net Worth
of Mariner immediately preceding the transaction;
(b) would, on the date of such transaction after giving pro
forma effect thereto and any related financing transactions as
if the same had occurred at the beginning of the applicable
four-quarter period, be permitted to incur at least $1.00 of
additional Indebtedness pursuant to the Fixed Charge Coverage
Ratio test set forth in the first paragraph of the covenant
described above under the caption Incurrence
of Indebtedness and Issuance of Preferred Stock; or
(c) would, on the date of such transaction after giving pro
forma effect thereto and any related financing transactions as
if the same had occurred at the beginning of the applicable
four-quarter period, have a Fixed Charge Coverage Ratio that is
not less than the Fixed Charged Coverage Ratio of Mariner and
its Restricted Subsidiaries immediately prior to such
transaction.
For purposes of this covenant, the sale, lease, conveyance,
assignment, transfer, or other disposition of all or
substantially all of the properties and assets of one or more
Subsidiaries of Mariner, which properties and
136
assets, if held by Mariner instead of such Subsidiaries, would
constitute all or substantially all of the properties and assets
of Mariner on a consolidated basis, shall be deemed to be the
transfer of all or substantially all of the assets of Mariner.
The surviving entity will succeed to, and be substituted for,
and may exercise every right and power of, Mariner under the
indenture, but, in the case of a lease of all or substantially
all of its assets, Mariner will not be released from the
obligation to pay the principal of and interest on the notes.
Although there is a limited body of case law interpreting the
phrase substantially all, there is no precise
established definition of the phrase under applicable law.
Accordingly, in certain circumstances there may be a degree of
uncertainty as to whether a particular transaction would involve
all or substantially all of the property or assets
of a Person.
Notwithstanding the restrictions described in the foregoing
clause (4), any Restricted Subsidiary may consolidate with,
merge into or transfer all or part of its properties and assets
to Mariner, Mariner may merge into a Restricted Subsidiary for
the purpose of reincorporating Mariner in another jurisdiction,
and any Restricted Subsidiary may consolidate with, merge into
or transfer all or part of its properties and assets to another
Restricted Subsidiary.
Transactions
with Affiliates
Mariner will not, and will not permit any of its Restricted
Subsidiaries to, make any payment to, or sell, lease, transfer
or otherwise dispose of any of its properties or assets to, or
purchase any property or assets from, or enter into or make or
amend any transaction, contract, agreement, understanding, loan,
advance or guarantee with, or for the benefit of, any Affiliate
of Mariner (each, an Affiliate Transaction),
unless:
(1) the Affiliate Transaction is on terms that are no less
favorable to Mariner or the relevant Restricted Subsidiary than
those that would have been obtained in a comparable transaction
by Mariner or such Restricted Subsidiary with an unrelated
Person; and
(2) Mariner delivers to the trustee:
(a) with respect to any Affiliate Transaction or series of
related Affiliate Transactions involving aggregate consideration
in excess of $10.0 million, a resolution of the Board of
Directors of Mariner set forth in an officers certificate
certifying that such Affiliate Transaction complies with this
covenant and that such Affiliate Transaction has been approved
by a majority of the disinterested members of the Board of
Directors of Mariner; and
(b) with respect to any Affiliate Transaction or series of
related Affiliate Transactions involving aggregate consideration
in excess of $30.0 million, an opinion as to the fairness
to Mariner or such Subsidiary of such Affiliate Transaction from
a financial point of view issued by an accounting, appraisal or
investment banking firm of national standing.
The following items will not be deemed to be Affiliate
Transactions and, therefore, will not be subject to the
provisions of the prior paragraph:
(1) any employment agreement or arrangement, stock option
or stock ownership plan, employee benefit plan, officer or
director indemnification agreement, restricted stock agreement,
severance agreement or other compensation plan or arrangement
entered into by Mariner or any of its Restricted Subsidiaries in
the ordinary course of business and payments, awards, grants or
issuances of securities pursuant thereto, including, without
limitation, pursuant to Mariners Equity Participation
Plan, as amended, and its Amended and Restated Stock Incentive
Plan, as amended;
(2) transactions between or among Mariner
and/or its
Restricted Subsidiaries;
(3) transactions with a Person (other than an Unrestricted
Subsidiary of Mariner) that is an Affiliate of Mariner solely
because Mariner owns, directly or through a Restricted
Subsidiary, an Equity Interest in, or controls, such Person;
137
(4) reasonable fees and expenses and compensation paid to,
and indemnity or insurance provided on behalf of, officers,
directors or employees of Mariner or any Restricted Subsidiaries
as determined in good faith by the Board of Directors;
(5) any issuance of Equity Interests (other than
Disqualified Stock) of Mariner to, or receipt of a capital
contribution from, Affiliates (or a Person that becomes an
Affiliate) of Mariner;
(6) Restricted Payments that do not violate the provisions
of the indenture described above under the caption
Restricted Payments;
(7) transactions between Mariner or any Restricted
Subsidiaries and any Person, a director of which is also a
director of Mariner or any direct or indirect parent company of
Mariner and such director is the sole cause for such Person to
be deemed an Affiliate of Mariner or any Restricted
Subsidiaries; provided, however, that such director
abstains from voting as director of Mariner or such direct or
indirect parent company, as the case may be, on any matter
involving such other Person;
(8) loans or advances to employees in the ordinary course
of business or consistent with past practice not to exceed
$5.0 million in the aggregate at any one time outstanding;
(9) advances to or reimbursements of employees for moving,
entertainment and travel expenses, drawing accounts and similar
expenditures in the ordinary course of business;
(10) any transaction in which Mariner or any of its
Restricted Subsidiaries, as the case may be, deliver to the
trustee a letter from an accounting, appraisal or investment
banking firm of national standing stating that such transaction
is fair to Mariner or such Restricted Subsidiary from a
financial point of view or that such transaction meets the
requirements of clause (i) of the preceding paragraph;
(11) the performance of obligations of Mariner or any of
its Restricted Subsidiaries under the terms of any written
agreement to which Mariner or any of its Restricted Subsidiaries
is a party on the Issue Date and which is described in this
prospectus, as these agreements may be amended, modified or
supplemented from time to time; provided, however, that any
future amendment, modification or supplement entered into after
the Issue Date will be permitted to the extent that its terms do
not materially and adversely affect the rights of any holders of
the notes (as determined in good faith by the Board of Directors
of Mariner) as compared to the terms of the agreements in effect
on the Issue Date; and
(12) (a) guarantees of performance by Mariner and its
Restricted Subsidiaries of Mariners Unrestricted
Subsidiaries in the ordinary course of business, except for
guarantees of Indebtedness in respect of borrowed money, and
(b) pledges of Equity Interests of Mariners
Unrestricted Subsidiaries for the benefit of lenders of
Mariners Unrestricted Subsidiaries.
Additional
Note Guarantees
The indenture will provide that if, after the Issue Date, any
Domestic Subsidiary that is not already a Guarantor has
outstanding or guarantees any other Indebtedness of Mariner or a
Guarantor in excess of a De Minimis Guaranteed Amount, then such
Domestic Subsidiary will become a Guarantor with respect to the
notes issued thereunder by executing and delivering a
supplemental indenture, in the form provided for in the
indenture, to the trustee within 180 days of the date on
which it guaranteed such Indebtedness.
Designation
of Restricted and Unrestricted Subsidiaries
The Board of Directors of Mariner may designate any Restricted
Subsidiary to be an Unrestricted Subsidiary if that designation
would not cause a Default. If a Restricted Subsidiary is
designated as an Unrestricted Subsidiary, the aggregate Fair
Market Value of all outstanding Investments owned by Mariner and
its Restricted Subsidiaries in the Subsidiary designated as
Unrestricted will be deemed to be an Investment made as of the
time of the designation and will reduce the amount available for
Restricted Payments under the covenant described above under the
caption Restricted Payments or under one
or more clauses of the definition of Permitted Investments, as
determined by Mariner. That designation will only be permitted
if the
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Investment would be permitted at that time and if the Restricted
Subsidiary otherwise meets the definition of an Unrestricted
Subsidiary.
Any designation of a Subsidiary of Mariner as an Unrestricted
Subsidiary will be evidenced to the trustee by filing with the
trustee a certified copy of a resolution of the Board of
Directors of Mariner giving effect to such designation and an
officers certificate certifying that such designation
complied with the preceding conditions and was permitted by the
covenant described above under the caption
Restricted Payments. If, at any time,
any Unrestricted Subsidiary would fail to meet the preceding
requirements as an Unrestricted Subsidiary, it will thereafter
cease to be an Unrestricted Subsidiary for purposes of the
indenture and any Indebtedness of such Subsidiary will be deemed
to be incurred by a Restricted Subsidiary of Mariner as of such
date and, if such Indebtedness is not permitted to be incurred
as of such date under the covenant described under the caption
Incurrence of Indebtedness and Issuance of
Preferred Stock, Mariner will be in default of such
covenant. The Board of Directors of Mariner may at any time
designate any Unrestricted Subsidiary to be a Restricted
Subsidiary of Mariner; provided that such designation
will be deemed to be an incurrence of Indebtedness by a
Restricted Subsidiary of Mariner of any outstanding Indebtedness
of such Unrestricted Subsidiary, and such designation will only
be permitted if (1) such Indebtedness is permitted under
the covenant described under the caption
Incurrence of Indebtedness and Issuance of
Preferred Stock, calculated on a pro forma basis as if
such designation had occurred at the beginning of the
four-quarter reference period; and (2) no Default or Event
of Default would be in existence following such designation.
Reports
Whether or not required by the rules and regulations of the SEC,
so long as any notes are outstanding, Mariner will file with the
SEC for public availability, within the time periods specified
in the SECs rules and regulations (unless the SEC will not
accept such a filing, in which case Mariner will furnish to the
holders of notes or cause the trustee to furnish to the holders
of notes, within the time periods specified in the SECs
rules and regulations):
(1) all quarterly and annual reports that would be required
to be filed with the SEC on
Forms 10-Q
and 10-K if
Mariner were required to file such reports; and
(2) all current reports that would be required to be filed
with the SEC on
Form 8-K
if Mariner were required to file such reports.
All such reports will be prepared in all material respects in
accordance with all of the rules and regulations applicable to
such reports. Each annual report on
Form 10-K
will include a report on Mariners consolidated financial
statements by Mariners certified independent accountants.
If, at any time, Mariner is no longer subject to the periodic
reporting requirements of the Exchange Act for any reason,
Mariner will nevertheless continue filing the reports specified
in the preceding paragraphs of this covenant with the SEC within
the time periods specified above unless the SEC will not accept
such a filing. Mariner will not take any action for the purpose
of causing the SEC not to accept any such filings. If,
notwithstanding the foregoing, the SEC will not accept
Mariners filings for any reason, Mariner will post the
reports referred to in the preceding paragraphs on its website
within the time periods that would apply if Mariner were
required to file those reports with the SEC.
If Mariner has designated any of its Subsidiaries as
Unrestricted Subsidiaries, then, to the extent material, the
quarterly and annual financial information required by the
preceding paragraphs will include a reasonably detailed
presentation, either on the face of the financial statements or
in the footnotes thereto, and in Managements Discussion
and Analysis of Financial Condition and Results of Operations,
of the financial condition and results of operations of Mariner
and its Restricted Subsidiaries separate from the financial
condition and results of operations of the Unrestricted
Subsidiaries of Mariner.
In addition, Mariner and the Guarantors agree that, for so long
as any notes remain outstanding, if at any time they are not
required to file the reports required by the preceding
paragraphs with the SEC, they will
139
furnish to the holders of notes and to securities analysts and
prospective investors, upon their request, the information
required to be delivered pursuant to Rule 144A(d)(4) under
the Securities Act.
Covenant
Termination
From and after the occurrence of an Investment Grade Rating
Event, we and our Restricted Subsidiaries will no longer be
subject to the provisions of the indenture described above under
the following headings:
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Repurchase at the Option of
Holders Change of Control,
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Repurchase at the Option of the
Holders Asset Sales,
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Certain Covenants Restricted
Payments,
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Certain Covenants Incurrence
of Indebtedness and Issuance of Preferred Stock,
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Certain Covenants Dividend
and Other Payment Restrictions Affecting Subsidiaries,
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clause (4) of the covenant listed under
Certain Covenants Merger,
Consolidation or Sale of Assets,
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Certain Covenants
Transactions with Affiliates, and
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Certain Covenants
Designation of Restricted and Unrestricted Subsidiaries.
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(collectively, the Eliminated Covenants). As
a result, after the date on which we and our Restricted
Subsidiaries are no longer subject to the Eliminated Covenants,
the notes will be entitled to substantially reduced covenant
protection.
Events of
Default and Remedies
Each of the following is an Event of Default:
(1) default for 30 days in the payment when due of
interest on, or Special Interest, if any, with respect to, the
notes;
(2) default in the payment when due (at maturity, upon
redemption or otherwise) of the principal of, or premium, if
any, on, the notes;
(3) failure by Mariner or any of its Restricted
Subsidiaries to comply with the provisions described under the
captions Repurchase at the Option of
Holders Change of Control,
Repurchase at the Option of
Holders Asset Sales, or
Certain Covenants Merger,
Consolidation or Sale of Assets;
(4) failure by Mariner or any of its Restricted
Subsidiaries for 60 days after notice to Mariner by the
trustee or the holders of at least 25% in aggregate principal
amount of the notes then outstanding voting as a single class to
comply with any of the other agreements in the indenture;
(5) default under any mortgage, indenture or instrument
under which there may be issued or by which there may be secured
or evidenced any Indebtedness for money borrowed by Mariner or
any of its Restricted Subsidiaries (or the payment of which is
guaranteed by Mariner or any of its Restricted Subsidiaries),
whether such Indebtedness or Guarantee now exists, or is created
after the date of the indenture, if that default:
(a) is caused by a failure to pay principal of, or interest
or premium, if any, on, such Indebtedness prior to the
expiration of the grace period provided in such Indebtedness on
the date of such default (a Payment
Default); or
(b) results in the acceleration of such Indebtedness prior
to its express maturity, and, in each case, the principal amount
of any such Indebtedness, together with the principal amount of
any other such Indebtedness under which there has been a Payment
Default or the maturity of which has been so accelerated,
aggregates $20.0 million or more; provided that if any such
default is cured or waived or any such acceleration rescinded,
or such Indebtedness is repaid, within a period of ten
140
Business Days from the continuation of such default beyond the
applicable grace period or the occurrence of such acceleration,
as the case may be, such Event of Default and any consequential
acceleration of the notes shall be automatically rescinded, so
long as such rescission does not conflict with any judgment or
decree;
(6) failure by Mariner or any of its Restricted
Subsidiaries to pay final judgments entered by a court or courts
of competent jurisdiction aggregating in excess of
$20.0 million (net of any amount with respect to which a
reputable and solvent insurance company has acknowledged
liability in writing), which judgments are not paid, discharged,
stayed or fully bonded for a period of 60 days (or, if
later, the date when payment is due pursuant to such judgment);
(7) (i) except as permitted by the indenture, any Note
Guarantee is held in any judicial proceeding to be unenforceable
or invalid or ceases for any reason to be in full force and
effect, or (ii) any Guarantor, or any Person acting on
behalf of any Guarantor, denies or disaffirms its obligations
under its Note Guarantee; and
(8) certain events of bankruptcy or insolvency described in
the indenture with respect to Mariner or any of its Restricted
Subsidiaries that is a Significant Subsidiary or any group of
Restricted Subsidiaries that, taken together, would constitute a
Significant Subsidiary.
In the case of an Event of Default arising from certain events
of bankruptcy or insolvency, with respect to Mariner, any
Restricted Subsidiary of Mariner that is a Significant
Subsidiary or any group of Restricted Subsidiaries of Mariner
that, taken together, would constitute a Significant Subsidiary,
all then outstanding notes will become due and payable
immediately without further action or notice. If any other Event
of Default occurs and is continuing, the trustee may and, at the
direction of the holders of at least 25% in aggregate principal
amount of the then outstanding notes shall, declare all of the
then outstanding notes to be due and payable immediately by
notice in writing to Mariner and, in case of a notice by
holders, also to the trustee specifying the respective Event of
Default and that it is a notice of acceleration.
Subject to certain limitations, holders of a majority in
aggregate principal amount of the then outstanding notes may
direct the trustee in its exercise of any trust or power. The
trustee may withhold from holders of the notes notice of any
continuing Default or Event of Default if it determines that
withholding notice is in their interest, except a Default or
Event of Default relating to the payment of principal, interest
or premium, if any, or Special Interest, if any.
Subject to the provisions of the indenture relating to the
duties of the trustee, in case an Event of Default occurs and is
continuing, the trustee will be under no obligation to exercise
any of the rights or powers under the indenture at the request
or direction of any holders of notes unless such holders have
offered to the trustee reasonable indemnity or security against
any loss, liability or expense. Except to enforce the right to
receive payment of principal, premium, if any, or interest or
Special Interest, if any, when due, no holder of a note may
pursue any remedy with respect to the indenture or the notes
unless:
(1) such holder has previously given the trustee notice
that an Event of Default is continuing;
(2) holders of at least 25% in aggregate principal amount
of the then outstanding notes have requested the trustee to
pursue the remedy;
(3) such holders have offered the trustee reasonable
security or indemnity against any loss, liability or expense;
(4) the trustee has not complied with such request within
60 days after the receipt of the request and the offer of
security or indemnity; and
(5) holders of a majority in aggregate principal amount of
the then outstanding notes have not given the trustee a
direction inconsistent with such request within such
60-day
period.
The holders of a majority in aggregate principal amount of the
notes then outstanding by notice to the trustee may, on behalf
of the holders of all of the notes, rescind an acceleration or
waive any existing Default
141
or Event of Default and its consequences under the indenture
except a continuing Default or Event of Default in the payment
of interest or premium or Special Interest, if any, on, or the
principal of, the notes.
Notwithstanding the foregoing, if an Event of Default specified
in clause (5) above shall have occurred and be continuing,
such Event of Default and any consequential acceleration shall
be automatically rescinded if (i) the Indebtedness that is
the subject of such Event of Default has been repaid, or
(ii) if the default relating to such Indebtedness is waived
or cured and if such Indebtedness has been accelerated, then the
holders thereof have rescinded their declaration of acceleration
in respect of such Indebtedness.
Mariner is required to deliver to the trustee annually a
statement regarding compliance with the indenture. Upon becoming
aware of any Default or Event of Default, Mariner is required
within five Business Days to deliver to the trustee a statement
specifying such Default or Event of Default.
No
Personal Liability of Directors, Officers, Employees and
Stockholders
No director, officer, employee, incorporator or stockholder of
Mariner or any Guarantor, as such, will have any liability for
any obligations of Mariner or the Guarantors under the notes,
the indenture, the Note Guarantees or for any claim based on, in
respect of, or by reason of, such obligations or their creation.
Each holder of notes by accepting a note waives and releases all
such liability. The waiver and release are part of the
consideration for issuance of the notes. The waiver may not be
effective to waive liabilities under the federal securities laws.
Legal
Defeasance and Covenant Defeasance
Mariner may at any time, at the option of its Board of Directors
evidenced by a resolution set forth in an Officers
Certificate, elect to have all of its obligations discharged
with respect to the outstanding notes and all obligations of the
Guarantors discharged with respect to their Note Guarantees
(Legal Defeasance) except for:
(1) the rights of holders of outstanding notes to receive
payments in respect of the principal of, or interest or premium
and Special Interest, if any, on, such notes when such payments
are due from the trust referred to below;
(2) Mariners obligations with respect to the notes
concerning issuing temporary notes, registration of notes,
mutilated, destroyed, lost or stolen notes and the maintenance
of an office or agency for payment and money for security
payments held in trust;
(3) the rights, powers, trusts, duties and immunities of
the trustee, and Mariners and the Guarantors
obligations in connection therewith;
(4) the optional redemption provisions of the
indenture; and
(5) the Legal Defeasance and Covenant Defeasance provisions
of the indenture.
In addition, Mariner may, at its option and at any time, elect
to have the obligations of Mariner and the Guarantors released
with respect to certain covenants (including its obligation to
make Change of Control Offers and Asset Sale Offers) that are
described in the indenture (Covenant
Defeasance) and thereafter any omission to comply with
those covenants will not constitute a Default or Event of
Default with respect to the notes. In the event Covenant
Defeasance occurs, certain events (not including non-payment,
bankruptcy, receivership, rehabilitation and insolvency events)
described under Events of Default and
Remedies will no longer constitute an Event of Default
with respect to the notes. If Mariner exercises either its Legal
Defeasance or Covenant Defeasance option, each Guarantor will be
released and relieved of any obligations under its Note
Guarantee and any security for the notes (other than the trust)
will be released.
In order to exercise either Legal Defeasance or Covenant
Defeasance:
(1) Mariner must irrevocably deposit with the trustee, in
trust, for the benefit of the holders of the notes, cash in
U.S. dollars, non-callable Government Securities, or a
combination of cash in U.S. dollars and non-callable
Government Securities, in amounts as will be sufficient, in the
opinion of a nationally
142
recognized investment bank, appraisal firm or firm of
independent public accountants, to pay the principal of, or
interest and premium and Special Interest, if any, on, the
outstanding notes on the stated date for payment thereof or on
the applicable redemption date, as the case may be, and Mariner
must specify whether the notes are being defeased to such stated
date for payment or to a particular redemption date;
(2) in the case of Legal Defeasance, Mariner must deliver
to the trustee an opinion of counsel reasonably acceptable to
the trustee confirming that (a) Mariner has received from,
or there has been published by, the Internal Revenue Service a
ruling or (b) since the date of the indenture, there has
been a change in the applicable federal income tax law, in
either case to the effect that, and based thereon such opinion
of counsel will confirm that, the holders of the outstanding
notes will not recognize income, gain or loss for federal income
tax purposes as a result of such Legal Defeasance and will be
subject to federal income tax on the same amounts, in the same
manner and at the same times as would have been the case if such
Legal Defeasance had not occurred; (3) in the case of
Covenant Defeasance, Mariner must deliver to the trustee an
opinion of counsel reasonably acceptable to the trustee
confirming that the holders of the outstanding notes will not
recognize income, gain or loss for federal income tax purposes
as a result of such Covenant Defeasance and will be subject to
federal income tax on the same amounts, in the same manner and
at the same times as would have been the case if such Covenant
Defeasance had not occurred;
(4) no Default or Event of Default has occurred and is
continuing on the date of such deposit (other than a Default or
Event of Default resulting from the borrowing of funds to be
applied to such deposit) and the deposit will not result in a
breach or violation of, or constitute a default under, any
Indebtedness incurred under clause (1) of Permitted Debt;
(5) such Legal Defeasance or Covenant Defeasance will not
result in a breach or violation of, or constitute a default
under, any material agreement or instrument (other than the
indenture) to which Mariner or any of its Subsidiaries is a
party or by which Mariner or any of its Subsidiaries is bound;
(6) Mariner must deliver to the trustee an officers
certificate stating that the deposit was not made by Mariner
with the intent of preferring the holders of notes over the
other creditors of Mariner with the intent of defeating,
hindering, delaying or defrauding any creditors of Mariner or
others; and
(7) Mariner must deliver to the trustee an officers
certificate and an opinion of counsel, each stating that all
conditions precedent relating to the Legal Defeasance or the
Covenant Defeasance have been complied with.
Amendment,
Supplement and Waiver
Except as provided in the next two succeeding paragraphs, the
indenture, the notes or the Note Guarantees may be amended or
supplemented with the consent of the holders of at least a
majority in aggregate principal amount of the notes then
outstanding (including, without limitation, consents obtained in
connection with a purchase of, or tender offer or exchange offer
for, notes), and any existing Default or Event of Default or
compliance with any provision of the indenture or the notes or
the Note Guarantees may be waived with the consent of the
holders of a majority in aggregate principal amount of the then
outstanding notes (including, without limitation, consents
obtained in connection with a purchase of, or tender offer or
exchange offer for, notes).
Without the consent of each holder of notes affected, an
amendment, supplement or waiver may not (with respect to any
notes held by a non-consenting holder):
(1) reduce the principal amount of notes whose holders must
consent to an amendment, supplement or waiver;
(2) reduce the principal of or change the fixed maturity of
any note or alter the provisions with respect to the redemption
of the notes (other than provisions relating to the covenants
described above under the caption Repurchase
at the Option of Holders);
143
(3) reduce the rate of or change the time for payment of
interest, including default interest, on any note;
(4) waive a Default or Event of Default in the payment of
principal of, or interest or premium, or Special Interest, if
any, on, the notes (except a rescission of acceleration of the
notes by the holders of at least a majority in aggregate
principal amount of the then outstanding notes and a waiver of
the payment default that resulted from such acceleration);
(5) make any note payable in money other than that stated
in the notes;
(6) make any change in the provisions of the indenture
relating to waivers of past Defaults or the rights of holders of
notes to receive payments of principal of, or interest or
premium or Special Interest, if any, on, the notes (other than
as permitted in clause (7) below);
(7) waive a redemption payment with respect to any note
(other than a payment required by one of the covenants described
above under the caption Repurchase at the
Option of Holders);
(8) allow any Guarantor to execute a supplemental indenture
and/or a
Note Guarantee with respect to the notes or release any
Guarantor from any of its obligations under its Note Guarantee
or the indenture, except in accordance with the terms of the
indenture; or
(9) make any change in the preceding amendment and waiver
provisions.
Notwithstanding the preceding, without the consent of any holder
of notes, Mariner, the Guarantors and the trustee may amend or
supplement the indenture, the notes or the Note Guarantees:
(1) to cure any ambiguity, defect or inconsistency;
(2) to provide for uncertificated notes in addition to or
in place of certificated notes;
(3) to provide for the assumption of Mariners or a
Guarantors obligations to holders of notes and Note
Guarantees in the case of a merger or consolidation or sale of
all or substantially all of Mariners or such
Guarantors assets, as applicable;
(4) to make any change that would provide any additional
rights or benefits to the holders of notes or that does not
adversely affect the legal rights under the indenture of any
such holder;
(5) to comply with requirements of the SEC in order to
effect or maintain the qualification of the indenture under the
Trust Indenture Act;
(6) to conform the text of the indenture, the Note
Guarantees or the notes to any provision of this Description of
Senior Notes;
(7) to provide for the issuance of additional notes in
accordance with the limitations set forth in the indenture as of
the date of the indenture;
(8) to allow any Guarantor to execute a supplemental
indenture
and/or a
Note Guarantee with respect to the notes or release Note
Guarantees pursuant to the terms of the indenture;
(9) to secure the notes; or
(10) to evidence and provide for the acceptance under the
indenture of a successor trustee.
The consent of the holders is not necessary under the indenture
to approve the particular form of any proposed amendment. It is
sufficient if such consent approves the substance of the
proposed amendment. After an amendment under the indenture
becomes effective, Mariner is required to mail to the holders a
notice briefly describing such amendment. However, the failure
to give such notice to all the holders, or any defect in the
notice, will not impair or affect the validity of the amendment.
144
Satisfaction
and Discharge
The indenture will be discharged and will cease to be of further
effect as to all notes issued thereunder, when:
(1) either:
(a) all notes that have been authenticated, except lost,
stolen or destroyed notes that have been replaced or paid and
notes for whose payment money has been deposited in trust and
thereafter repaid to Mariner, have been delivered to the trustee
for cancellation; or
(b) all notes that have not been delivered to the trustee
for cancellation have become due and payable by reason of the
mailing of a notice of redemption or otherwise or will become
due and payable within one year, and Mariner or any Guarantor
has irrevocably deposited or caused to be deposited with the
trustee as trust funds in trust solely for the benefit of the
holders, cash in U.S. dollars, non-callable Government
Securities, or a combination of cash in U.S. dollars and
noncallable Government Securities, in amounts as will be
sufficient, without consideration of any reinvestment of
interest, to pay and discharge the entire indebtedness on the
notes not delivered to the trustee for cancellation for
principal, premium and Special Interest, if any, and accrued
interest to the date of maturity or redemption;
(2) no Default or Event of Default has occurred and is
continuing on the date of the deposit (other than a Default or
Event of Default resulting from the borrowing of funds to be
applied to such deposit) and the deposit will not result in a
breach or violation of, or constitute a default under, any other
instrument to which Mariner or any Guarantor is a party or by
which Mariner or any Guarantor is bound;
(3) Mariner or any Guarantor has paid or caused to be paid
all sums payable by it under the indenture; and
(4) Mariner has delivered irrevocable instructions to the
trustee under the indenture to apply the deposited money toward
the payment of the notes at maturity or on the redemption date,
as the case may be.
In addition, Mariner must deliver an officers certificate
and an opinion of counsel to the trustee stating that all
conditions precedent to satisfaction and discharge have been
satisfied.
Concerning
the Trustee
If the trustee becomes a creditor of Mariner or any Guarantor,
the indenture limits the right of the trustee to obtain payment
of claims in certain cases, or to realize on certain property
received in respect of any such claim as security or otherwise.
The trustee will be permitted to engage in other transactions;
however, if it acquires any conflicting interest (as defined in
the Trust Indenture Act) after a Default has occurred and is
continuing, it must eliminate such conflict within 90 days,
apply to the SEC for permission to continue as trustee (if the
indenture has been qualified under the Trust Indenture Act) or
resign.
The holders of a majority in aggregate principal amount of the
then outstanding notes will have the right to direct the time,
method and place of conducting any proceeding for exercising any
remedy available to the trustee, subject to certain exceptions.
The indenture provides that in case an Event of Default occurs
and is continuing, the trustee will be required, in the exercise
of its power, to use the degree of care of a prudent man in the
conduct of his own affairs. Subject to such provisions, the
trustee will be under no obligation to exercise any of its
rights or powers under the indenture at the request of any
holder of notes, unless such holder has offered to the trustee
security and indemnity satisfactory to it against any loss,
liability or expense.
Additional
Information
Anyone who receives this prospectus may obtain a copy of the
indenture and registration rights agreement without charge by
writing to Mariner Energy, Inc., One Briar Lake Plaza,
Suite 2000, 2000 West Sam Houston Parkway South,
Houston, Texas 77042.
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Book-Entry;
Delivery and Form
Except as set forth below, new notes will be issued in
registered, global form (global notes).
The global notes will be deposited upon issuance with the
trustee as custodian for The Depository Trust Company
(DTC), in New York, New York, and registered in the
name of DTC or its nominee, in each case, for credit to an
account of a direct or indirect participant in DTC as described
below.
Except as set forth below, the global notes may be transferred,
in whole and not in part, only to another nominee of DTC or to a
successor of DTC or its nominee. Beneficial interests in the
global notes may not be exchanged for definitive notes in
registered certificated form (certificated notes)
except in the limited circumstances described below. See
Exchange of Global Notes for
Certificated Notes. Except in the limited circumstances
described below, owners of beneficial interests in the global
notes will not be entitled to receive physical delivery of notes
in certificated form.
Transfers of beneficial interests in the global notes will be
subject to the applicable rules and procedures of DTC and its
direct or indirect participants (including, if applicable, those
of Euroclear and Clearstream), which may change from time to
time.
Depository
Procedures
The following description of the operations and procedures of
DTC, Euroclear and Clearstream are provided solely as a matter
of convenience. These operations and procedures are solely
within the control of the respective settlement systems and are
subject to changes by them. Mariner takes no responsibility for
these operations and procedures and urges investors to contact
the system or their participants directly to discuss these
matters.
DTC has advised Mariner that DTC is a limited-purpose trust
company created to hold securities for its participating
organizations (collectively, the Participants) and
to facilitate the clearance and settlement of transactions in
those securities between the Participants through electronic
book-entry changes in accounts of its Participants. The
Participants include securities brokers and dealers (including
the initial purchasers), banks, trust companies, clearing
corporations and certain other organizations. Access to
DTCs system is also available to other entities such as
banks, brokers, dealers and trust companies that clear through
or maintain a custodial relationship with a Participant, either
directly or indirectly (collectively, the Indirect
Participants). Persons who are not Participants may
beneficially own securities held by or on behalf of DTC only
through the Participants or the Indirect Participants. The
ownership interests in, and transfers of ownership interests in,
each security held by or on behalf of DTC are recorded on the
records of the Participants and Indirect Participants.
Investors in the global notes who are Participants may hold
their interests therein directly through DTC. Investors in the
global notes who are not Participants may hold their interests
therein indirectly through organizations (including Euroclear
and Clearstream) which are Participants. Euroclear and
Clearstream will hold interests in the global notes on behalf of
their participants through customers securities accounts
in their respective names on the books of their respective
depositories, which are Euroclear Bank S.A./N.V, as operator of
Euroclear, and Citibank, N.A., as operator of Clearstream. All
interests in a global note, including those held through
Euroclear or Clearstream, may be subject to the procedures and
requirements of DTC. Those interests held through Euroclear or
Clearstream may also be subject to the procedures and
requirements of such systems. The laws of some states require
that certain persons take physical delivery in definitive form
of securities that they own. Consequently, the ability to
transfer beneficial interests in a global note to such persons
will be limited to that extent. Because DTC can act only on
behalf of the Participants, which in turn act on behalf of the
Indirect Participants, the ability of a person having beneficial
interests in a global note to pledge such interests to persons
that do not participate in the DTC system, or otherwise take
actions in respect of such interests, may be affected by the
lack of a physical certificate evidencing such interests.
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Except as
described below, owners of interests in the global notes will
not have notes registered in their names, will not receive
physical delivery of notes in certificated form and will not be
considered the registered owners or Holders thereof
under the Indenture for any purpose.
Payments in respect of the principal of, and interest and
premium, if any, and Special Interest, if any, on a global note
registered in the name of DTC or its nominee will be payable to
DTC in its capacity as the registered holder under the
Indenture. Under the terms of the Indenture, Mariner, the
subsidiary guarantors of the notes and the Trustee will treat
the persons in whose names the notes, including the global
notes, are registered as the owners of the notes for the purpose
of receiving payments and for all other purposes. Consequently,
neither Mariner, the subsidiary guarantors of the notes, the
trustee nor any agent of Mariner, the subsidiary guarantors of
the notes or the trustee has or will have any responsibility or
liability for:
(1) any aspect of DTCs records or any
Participants or Indirect Participants records
relating to or payments made on account of beneficial ownership
interest in the global notes or for maintaining, supervising or
reviewing any of DTCs records or any Participants or
Indirect Participants records relating to the beneficial
ownership interests in the global notes; or
(2) any other matter relating to the actions and practices
of DTC or any of its Participants or Indirect Participants.
DTC has advised Mariner that its current practice, upon receipt
of any payment in respect of securities such as the notes
(including principal and interest), is to credit the accounts of
the relevant Participants with the payment on the payment date
unless DTC has reason to believe that it will not receive
payment on such payment date. Each relevant Participant is
credited with an amount proportionate to its beneficial
ownership of an interest in the principal amount of the relevant
security as shown on the records of DTC. Payments by the
Participants and the Indirect Participants to the beneficial
owners of notes will be governed by standing instructions and
customary practices and will be the responsibility of the
Participants or the Indirect Participants and will not be the
responsibility of DTC, the trustee or Mariner. Neither Mariner
nor the trustee will be liable for any delay by DTC or any of
the Participants or the Indirect Participants in identifying the
beneficial owners of the notes, and we and the trustee may
conclusively rely on and will be protected in relying on
instructions from DTC or its nominee for all purposes.
Transfers between the Participants will be effected in
accordance with DTCs procedures, and will be settled in
same-day funds, and transfers between participants in Euroclear
and Clearstream will be effected in accordance with their
respective rules and operating procedures.
Cross-market transfers between the Participants, on the one
hand, and Euroclear or Clearstream participants, on the other
hand, will be effected through DTC in accordance with DTCs
rules on behalf of Euroclear or Clearstream, as the case may be,
by their respective depositaries; however, such cross-market
transactions will require delivery of instructions to Euroclear
or Clearstream, as the case may be, by the counterparty in such
system in accordance with the rules and procedures and within
the established deadlines (Brussels time) of such system.
Euroclear or Clearstream, as the case may be, will, if the
transaction meets its settlement requirements, deliver
instructions to its respective depositary to take action to
effect final settlement on its behalf by delivering or receiving
interests in the relevant global note in DTC, and making or
receiving payment in accordance with normal procedures for
same-day funds settlement applicable to DTC. Euroclear
participants and Clearstream participants may not deliver
instructions directly to the depositories for Euroclear or
Clearstream.
DTC has advised Mariner that it will take any action permitted
to be taken by a holder of notes only at the direction of one or
more Participants to whose account DTC has credited the
interests in the global notes and only in respect of such
portion of the aggregate principal amount of the notes as to
which such Participant or Participants has or have given such
direction. However, if there is an Event of Default under the
notes, DTC reserves the right to exchange the global notes for
legended notes in certificated form, and to distribute such
notes to its Participants.
Although DTC, Euroclear and Clearstream have agreed to the
foregoing procedures to facilitate transfers of interests in
global notes among participants in DTC, Euroclear and
Clearstream, they are under no
147
obligation to perform or to continue to perform such procedures,
and may discontinue such procedures at any time. None of
Mariner, the trustee and any of their respective agents will
have any responsibility for the performance by DTC, Euroclear or
Clearstream or their respective participants or indirect
participants of their respective obligations under the rules and
procedures governing their operations.
Exchange
of Global Notes for Certificated Notes
A global note is exchangeable for certificated notes if:
(1) DTC (a) notifies Mariner that it is unwilling or
unable to continue as depositary for the global notes or
(b) has ceased to be a clearing agency registered under the
Exchange Act and, in either case, Mariner fails to appoint a
successor depositary;
(2) Mariner, at its option, notifies the trustee in writing
that it elects to cause the issuance of the certificated
notes; or
(3) there has occurred and is continuing a Default or Event
of Default with respect to the notes.
In addition, beneficial interests in a global note may be
exchanged for certificated notes upon prior written notice given
to the trustee by or on behalf of DTC in accordance with the
indenture. In all cases, certificated notes delivered in
exchange for any global note or beneficial interests in global
notes will be registered in the names, and issued in any
approved denominations, requested by or on behalf of the
depositary (in accordance with its customary procedures).
Same Day
Settlement and Payment
Mariner will make payments in respect of the notes represented
by the global notes (including principal, premium, if any,
interest and Special Interest, if any) by wire transfer of
immediately available funds to the accounts specified by DTC or
its nominee. Mariner will make all payments of principal,
interest and premium, if any, and Special Interest, if any, with
respect to certificated notes by wire transfer of immediately
available funds to the accounts specified by the holders of the
certificated notes or, if no such account is specified, by
mailing a check to each such holders registered address.
The notes represented by the global notes are expected to be
eligible to trade in
PORTALsm
and to trade in DTCs Same-Day Funds Settlement System, and
any permitted secondary market trading activity in such notes
will, therefore, be required by DTC to be settled in immediately
available funds. Mariner expects that secondary trading in any
certificated notes will also be settled in immediately available
funds.
Because of time zone differences, the securities account of a
Euroclear or Clearstream participant purchasing an interest in a
global note from a Participant will be credited, and any such
crediting will be reported to the relevant Euroclear or
Clearstream participant, during the securities settlement
processing day (which must be a business day for Euroclear and
Clearstream) immediately following the settlement date of DTC.
DTC has advised us that cash received in Euroclear or
Clearstream as a result of sales of interests in a global note
by or through a Euroclear or Clearstream participant to a
Participant will be received with value on the settlement date
of DTC but will be available in the relevant Euroclear or
Clearstream cash account only as of the business day for
Euroclear or Clearstream following DTCs settlement date.
Certain
Definitions
Set forth below are certain defined terms used in the indenture.
Reference is made to the indenture for a full disclosure of all
defined terms used therein, as well as any other capitalized
terms used herein for which no definition is provided.
Acquired Debt means, with respect to any
specified Person:
(1) Indebtedness of any other Person existing at the time
such other Person is merged with or into or became a Subsidiary
of such specified Person, whether or not such Indebtedness is
incurred in connection with, or in contemplation of, such other
Person merging with or into, or becoming a Restricted Subsidiary
148
of, such specified Person, but excluding Indebtedness which is
extinguished, retired or repaid in connection with such Person
merging with or becoming a Subsidiary of such specified
Person; and
(2) Indebtedness secured by a Lien encumbering any asset
acquired by such specified Person.
Additional Assets means:
(1) any assets used or useful in the Oil and Gas Business,
other than Indebtedness or Capital Stock;
(2) the Capital Stock of a Person that becomes a Restricted
Subsidiary as a result of the acquisition of such Capital Stock
by Mariner or any of its Restricted Subsidiaries; or
(3) Capital Stock constituting a minority interest in any
Person that at such time is a Restricted Subsidiary;
provided, however, that any such Restricted Subsidiary described
in clause (2) or (3) is primarily engaged in the Oil
and Gas Business.
Adjusted Consolidated Net Tangible Assets
means (without duplication), as of the date of determination:
(1) the sum of:
(a) discounted future net revenue from proved crude oil and
natural gas reserves of Mariner and its Restricted Subsidiaries
calculated in accordance with SEC guidelines before any state or
federal income taxes, as estimated in a reserve report prepared
as of the end of the fiscal year ending at least 91 days
prior to the date of determination (or for the period prior to
the earlier of April 1, 2006 and the date of the reserve
report for 2006 is available, as of June 30, 2005), which
reserve report is prepared or audited by independent petroleum
engineers as increased by, as of the date of
determination, the discounted future net revenue of:
(i) estimated proved crude oil and natural gas reserves of
Mariner and its Restricted Subsidiaries attributable to
acquisitions consummated since the date of such reserve
report, and
(ii) estimated crude oil and natural gas reserves of
Mariner and its Restricted Subsidiaries attributable to
extensions, discoveries and other additions and upward
determinations of estimates of proved crude oil and natural gas
reserves (including previously estimated development costs
incurred during the period and the accretion of discount since
the prior period end) due to exploration, development or
exploitation, production or other activities which reserves were
not reflected in such reserve report which would, in accordance
with standard industry practice, result in such determinations,
in each case calculated in accordance with SEC guidelines
(utilizing the prices utilized in such year-end reserve report),
and decreased by, as of the date of determination, the
discounted future net revenue attributable to:
(iii) estimated proved crude oil and natural gas reserves
of Mariner and its Restricted Subsidiaries reflected in such
reserve report produced or disposed of since the date of such
reserve report, and
(iv) reductions in the estimated oil and natural gas
reserves of Mariner and its Restricted Subsidiaries reflected in
such reserve report since the date of such reserve report
attributable to downward determinations of estimates of proved
crude oil and natural gas reserves due to exploration,
development or exploitation, production or other activities
conducted or otherwise occurring since the date of such reserve
report which would, in accordance with standard industry
practice, result in such determinations, in each case calculated
in accordance with SEC guidelines (utilizing the prices utilized
in such reserve report);
provided, however, that, in the case of each of the
determinations made pursuant to clauses (i) through (iv),
such increases and decreases shall be estimated by
Mariners engineers, except that if as a result of such
acquisitions, dispositions, discoveries, extensions or
revisions, there is a Material
149
Change, then such increases and decreases in the discounted
future net revenue shall be confirmed in writing by an
independent petroleum engineer;
(b) the capitalized costs that are attributable to crude
oil and natural gas properties of Mariner and its Restricted
Subsidiaries to which no proved crude oil and natural gas
reserves are attributable, based on Mariners books and
records as of a date no earlier than the date of Mariners
latest available annual or quarterly financial statements;
(c) the Net Working Capital (excluding, to the extent
included in the determination of discounted future net revenues
under clause (1)(a) above, any adjustments made pursuant to
FAS 143) as of a date no earlier than the date of
Mariners latest available annual or quarterly financial
statements; and
(d) the greater of (i) the net book value as of a date
no earlier than the date of Mariners latest available
annual or quarterly financial statements and (ii) the
appraised value, as estimated by independent appraisers, of
other tangible assets of Mariner and its Restricted Subsidiaries
as of a date no earlier than the date of Mariners latest
available annual or quarterly financial statements (provided
that Mariner shall not be required to obtain such an appraisal
of such assets if no such appraisal has been performed);
minus
(2) the sum of:
(a) Minority Interests;
(b) any net natural gas balancing liabilities of Mariner
and its Restricted Subsidiaries reflected in Mariners
latest audited financial statements;
(c) to the extent included in clause (1)(a) above, the
discounted future net revenue, calculated in accordance with SEC
guidelines (utilizing the same prices in Mariners year-end
reserve report), attributable to reserves subject to
participation interests, overriding royalty interests or other
interests of third parties, pursuant to participation,
partnership, vendor financing or other agreements then in
effect, or which otherwise are required to be delivered to third
parties;
(d) to the extent included in clause (1)(a) above, the
discounted future net revenue calculated in accordance with SEC
guidelines (utilizing the same prices utilized in Mariners
year-end reserve report), attributable to reserves that are
required to be delivered to third parties to fully satisfy the
obligations of Mariner and its Restricted Subsidiaries with
respect to Volumetric Production Payments on the schedules
specified with respect thereto; and
(e) the discounted future net revenue, calculated in
accordance with SEC guidelines, attributable to reserves subject
to Dollar-Denominated Production Payments that, based on the
estimates of production included in determining the discounted
future net revenue specified in the immediately preceding
clause (i)(a) (utilizing the same prices utilized in
Mariners year-end reserve report), would be necessary to
satisfy fully the obligations of Mariner and its Restricted
Subsidiaries with respect to Dollar-Denominated Production
Payments on the schedules specified with respect thereto.
If Mariner changes its method of accounting from the full cost
method to the successful efforts method or a similar method of
accounting, Adjusted Consolidated Net Tangible
Assets will continue to be calculated as if Mariner were
still using the full cost method of accounting.
Affiliate of any specified Person means any
other Person directly or indirectly controlling or controlled by
or under direct or indirect common control with such specified
Person. For purposes of this definition, control, as
used with respect to any Person, means the possession, directly
or indirectly, of the power to direct or cause the direction of
the management or policies of such Person, whether through the
ownership of voting securities, by agreement or otherwise. For
purposes of this definition, the terms controlling,
controlled by and under common control
with have correlative meanings.
150
Asset Sale means:
(1) the sale, lease, conveyance or other disposition of any
assets or rights (including by way of a Production Payment or a
sale and leaseback transaction); provided that the sale,
lease, conveyance or other disposition of all or substantially
all of the assets of Mariner and its Restricted Subsidiaries
taken as a whole will be governed by the provisions of the
indenture described above under the caption
Repurchase at the Option of
Holders Change of Control
and/or the
provisions described above under the caption
Certain Covenants Merger,
Consolidation or Sale of Assets and not by the provisions
of the Asset Sale covenant; and
(2) the issuance of Equity Interests in any of
Mariners Restricted Subsidiaries or the sale of Equity
Interests held by Mariner or its Subsidiaries in any of its
Subsidiaries.
Notwithstanding the preceding, none of the following items will
be deemed to be an Asset Sale:
(1) any single transaction or series of related
transactions that involves assets having a Fair Market Value of
less than $5.0 million;
(2) a transfer of assets between or among Mariner and its
Restricted Subsidiaries;
(3) an issuance of Equity Interests by a Restricted
Subsidiary of Mariner to Mariner or to a Restricted Subsidiary
of Mariner;
(4) the sale or lease of products, services or accounts
receivable in the ordinary course of business and any sale or
other disposition of damaged, worn-out or obsolete assets in the
ordinary course of business;
(5) the sale or other disposition of cash or Cash
Equivalents;
(6) a Restricted Payment that does not violate the covenant
described above under the caption Certain
Covenants Restricted Payments;
(7) a Permitted Investment, including, without limitation,
unwinding Hedging Obligations;
(8) a disposition of Hydrocarbons or mineral products
inventory in the ordinary course of business;
(9) the sale or transfer (whether or not in the ordinary
course of business) of crude oil and natural gas properties or
direct or indirect interests in real property; provided,
that at the time of such sale or transfer such properties do not
have associated with them any proved reserves;
(10) the farm-out, lease or sublease of developed or
undeveloped crude oil or natural gas properties owned or held by
Mariner or such Restricted Subsidiary in exchange for crude oil
and natural gas properties owned or held by another Person;
(11) any trade or exchange by Mariner or any Restricted
Subsidiaries of oil and gas properties or other properties or
assets for oil and gas properties or other properties or assets
owned or held by another Person, provided that the fair market
value of the properties or assets traded or exchanged by Mariner
or such Restricted Subsidiary (together with any cash) is
reasonably equivalent to the fair market value of the properties
or assets (together with any cash) to be received by Mariner or
such Restricted Subsidiary, and provided further that any net
cash received must be applied in accordance with the provisions
described above under the caption Repurchase
at the Option of Holders Asset Sales;
(12) the creation or perfection of a Lien (but not, except
to the extent contemplated in clause (13) below, the
sale or other disposition of the properties or assets subject to
such Lien);
(13) the creation or perfection of a Permitted Lien and the
exercise by any Person in whose favor a Permitted Lien is
granted of any of its rights in respect of that Permitted Lien;
(14) the licensing or sublicensing of intellectual
property, including, without limitation, licenses for seismic
data, in the ordinary course of business and which do not
materially interfere with the business of Mariner and its
Restricted Subsidiaries; and
151
(15) a surrender or waiver of contract rights or the
settlement, release or surrender of contract, tort or other
claims of any kind.
Attributable Debt in respect of a sale and
leaseback transaction means, at the time of determination, the
present value of the obligation of the lessee for net rental
payments during the remaining term of the lease included in such
sale and leaseback transaction including any period for which
such lease has been extended or may, at the option of the
lessor, be extended. Such present value shall be calculated
using a discount rate equal to the rate of interest implicit in
such transaction, determined in accordance with GAAP.
Beneficial Owner has the meaning assigned to
such term in
Rule 13d-3
and
Rule 13d-5
under the Exchange Act, except that in calculating the
beneficial ownership of any particular person (as
that term is used in Section 13(d)(3) of the Exchange Act),
such person will be deemed to have beneficial
ownership of all securities that such person has the
right to acquire by conversion or exercise of other securities,
whether such right is currently exercisable or is exercisable
only after the passage of time. The terms
Beneficial Ownership, Beneficially
Owns and Beneficially Owned have a
corresponding meaning.
Board of Directors means:
(1) with respect to a corporation, the board of directors
of the corporation or any committee thereof duly authorized to
act on behalf of such board;
(2) with respect to a partnership, the Board of Directors
of the general partner of the partnership;
(3) with respect to a limited liability company, the
managing member or members or any controlling committee of
managing members thereof; and
(4) with respect to any other Person, the board or
committee of such Person serving a similar function.
Business Day means each day that is not a
Saturday, Sunday or other day on which banking institutions in
New York, New York or another place of payment are authorized or
required by law to close.
Capital Lease Obligation means, at the time
any determination is to be made, the amount of the liability in
respect of a capital lease that would at that time be required
to be capitalized on a balance sheet prepared in accordance with
GAAP, and the Stated Maturity thereof shall be the date of the
last payment of rent or any other amount due under such lease
prior to the first date upon which such lease may be prepaid by
the lessee without payment of a penalty.
Capital Stock means:
(1) in the case of a corporation, corporate stock;
(2) in the case of an association or business entity, any
and all shares, interests, participations, rights or other
equivalents (however designated) of corporate stock;
(3) in the case of a partnership or limited liability
company, partnership interests (whether general or limited) or
membership interests; and
(4) any other interest or participation that confers on a
Person the right to receive a share of the profits and losses
of, or distributions of assets of, the issuing Person, but
excluding from all of the foregoing any debt securities
convertible into Capital Stock, whether or not such debt
securities include any right of participation with Capital Stock.
Cash Equivalents means:
(1) United States dollars;
(2) securities issued or directly and fully guaranteed or
insured by the United States government or any agency or
instrumentality of the United States government (provided
that the full faith and credit of the United States is
pledged in support of those securities) having maturities of not
more than one year from the date of acquisition;
152
(3) marketable general obligations issued by any state of
the United States of America or any political subdivision of any
such state or any public instrumentality thereof maturing within
one year from the date of acquisition thereof and, at the time
of acquisition thereof, having a credit rating of A
or better from either S&P or Moodys;
(4) certificates of deposit, demand deposit accounts and
eurodollar time deposits with maturities of one year or less
from the date of acquisition, bankers acceptances with
maturities not exceeding one year and overnight bank deposits,
in each case, with any domestic commercial bank having capital
and surplus in excess of $500.0 million and a Thomson Bank
Watch Rating of B or better;
(5) repurchase obligations with a term of not more than
seven days for underlying securities of the types described in
clauses (2), (3) and (4) above entered into with
any financial institution meeting the qualifications specified
in clause (4) above;
(6) commercial paper having one of the two highest ratings
obtainable from Moodys or S&P and, in each case,
maturing within six months after the date of
acquisition; and
(7) money market funds at least 95% of the assets of which
constitute Cash Equivalents of the kinds described in
clauses (1) through (6) of this definition.
Change of Control means the occurrence of any
of the following:
(1) the direct or indirect sale, lease, transfer,
conveyance or other disposition (other than by way of merger or
consolidation), in one or a series of related transactions, of
all or substantially all of the properties or assets of Mariner
and its Subsidiaries taken as a whole to any person
(as that term is used in Section 13(d) of the Exchange Act);
(2) the adoption of a plan relating to the liquidation or
dissolution of Mariner;
(3) the consummation of any transaction (including, without
limitation, any merger or consolidation), the result of which is
that any person (as defined above) becomes the
Beneficial Owner, directly or indirectly, of more than 50% of
the Voting Stock of Mariner, measured by voting power rather
than number of shares; or
(4) during any period of two consecutive years, Continuing
Directors cease to constitute a majority of the Board of
Directors of Mariner.
Change of Control Triggering Event means the
occurrence of both a Change of Control and a Rating Decline with
respect to the notes.
Consolidated Cash Flow means, with respect to
any specified Person for any period, the Consolidated Net Income
of such Person for such period plus, without duplication:
(1) an amount equal to any extraordinary loss plus any net
loss realized by such Person or any of its Restricted
Subsidiaries in connection with an Asset Sale (together with any
related provision for taxes and any related non-recurring
charges relating to any premium or penalty paid, write-off of
deferred financing costs or other financial recapitalization
charges in connection with redeeming or retiring any
Indebtedness prior to its Stated Maturity), to the extent such
losses were deducted in computing such Consolidated Net Income;
plus
(2) provision for taxes based on income or profits of such
Person and its Restricted Subsidiaries for such period, to the
extent that such provision for taxes was deducted in computing
such Consolidated Net Income; plus
(3) the Fixed Charges of such Person and its Restricted
Subsidiaries for such period, to the extent that such Fixed
Charges were deducted in computing such Consolidated Net Income;
plus
(4) depreciation, depletion, amortization (including
amortization of intangibles but excluding amortization of
prepaid cash expenses that were paid in a prior period),
impairment and other non-cash expenses (excluding any such
non-cash expense to the extent that it represents an accrual of
or reserve for
153
cash expenses in any future period or amortization of a prepaid
cash expense that was paid in a prior period) of such Person and
its Restricted Subsidiaries for such period to the extent that
such depreciation, depletion, amortization, impairment and other
non-cash expenses were deducted in computing such Consolidated
Net Income; minus
(5) non-cash items increasing such Consolidated Net Income
for such period, other than items that were accrued in the
ordinary course of business, and minus
(6) the sum of (a) the amount of deferred revenues
that are amortized during such period and are attributable to
reserves that are subject to Volumetric Production Payments and
(b) amounts recorded in accordance with GAAP as repayments
of principal and interest pursuant to Dollar-Denominated
Production Payments, in each case, on a consolidated basis and
determined in accordance with GAAP.
Notwithstanding the foregoing, the provision for taxes on the
income or profits of, and the depreciation, depletion and
amortization and other non-cash charges and expenses of, a
Restricted Subsidiary of the referent Person shall be added to
Consolidated Net Income to compute Consolidated Cash Flow only
to the extent (and in the same proportion) that the Net Income
of such Restricted Subsidiary was included in calculating the
Consolidated Net Income of such Person and only if a
corresponding amount would be permitted at the date of
determination to be dividended to the referent Person by such
Restricted Subsidiary without prior governmental approval (that
has not been obtained), and without direct or indirect
restriction pursuant to the terms of its charter and all
agreements, instruments, judgments, decrees, orders, statutes,
rules and governmental regulations applicable to that Restricted
Subsidiary or its stockholders.
Consolidated Net Income means, with respect
to any specified Person for any period, the aggregate of the Net
Income of such Person and its Restricted Subsidiaries for such
period, on a consolidated basis, determined in accordance with
GAAP; provided that:
(1) the Net Income (but not loss) of any Person that is not
a Restricted Subsidiary or that is accounted for by the equity
method of accounting will be included only to the extent of the
amount of dividends or similar distributions paid in cash to the
specified Person or a Restricted Subsidiary of the Person;
(2) the Net Income of any Restricted Subsidiary will be
excluded to the extent that the declaration or payment of
dividends or similar distributions by that Restricted Subsidiary
of that Net Income is not at the date of determination permitted
without any prior governmental approval (that has not been
obtained) or, directly or indirectly, by operation of the terms
of its charter or any agreement, instrument, judgment, decree,
order, statute, rule or governmental regulation applicable to
that Restricted Subsidiary or its stockholders;
(3) the cumulative effect of a change in accounting
principles will be excluded;
(4) income resulting from transfers of assets (other than
cash) between such Person or any of its Restricted Subsidiaries,
on the one hand, and an Unrestricted Subsidiary, on the other
hand, will be excluded;
(5) any gain (loss) realized upon the sale or other
disposition of any property, plant or equipment of such Person
or its consolidated Restricted Subsidiaries (including pursuant
to any sale or leaseback transaction) which is not sold or
otherwise disposed of in the ordinary course of business and any
gain (loss) realized upon the sale or other disposition of any
Capital Stock of any Person will be excluded;
(6) any asset impairment writedowns on Oil and Gas
Properties under GAAP or SEC guidelines will be excluded;
(7) any unrealized non-cash gains or losses or charges in
respect of hedge or non-hedge derivatives (including those
resulting from the application of FAS 133) will be
excluded; and
(8) to the extent deducted in the calculation of Net
Income, any non-cash or nonrecurring charges associated with any
premium or penalty paid, write-off of deferred financing costs
or other financial
154
recapitalization charges in connection with redeeming or
retiring any Indebtedness prior to its Stated Maturity will be
excluded; and
(9) items classified as extraordinary or nonrecurring gains
and losses (less all fees and expenses related thereto) or
expenses (including without limitation, severance, relocation,
other restructuring costs and expense arising from the
transactions closing contemporaneously with the offering of the
old notes), and the related tax effects according to GAAP, shall
be excluded.
Consolidated Net Worth means, with respect to
any specified Person as of any date, the sum of:
(1) the consolidated equity of the common stockholders of
such Person and its consolidated Subsidiaries as of such date;
plus
(2) the respective amounts reported on such Persons
balance sheet as of such date with respect to any series of
preferred stock (other than Disqualified Stock) that by its
terms is not entitled to the payment of dividends unless such
dividends may be declared and paid only out of net earnings in
respect of the year of such declaration and payment, but only to
the extent of any cash received by such Person upon issuance of
such preferred stock.
Continuing Directors means, as of any date of
determination, any member of the Board of Directors of Mariner
who:
(1) was a member of such Board of Directors on the Issue
Date; or
(2) was nominated for election or elected to such Board of
Directors with the approval of a majority of the Continuing
Directors who were members of such Board of Directors at the
time of such nomination or election.
Credit Agreement means that certain Amended
and Restated Credit Agreement, dated as of March 2, 2006 by
and among Mariner and Mariner Energy Resources, Inc., as
borrowers, Union Bank of California, N.A., as administrative
agent and issuing lender, BNP Paribas, as syndication agent, and
the lenders from time to time party thereto, providing for up to
$540 million of revolving credit and term loan borrowings
and letters of credit, including any related notes, Guarantees,
collateral documents, instruments and agreements executed in
connection therewith, and, in each case, as amended, restated,
modified, renewed, refunded, replaced (whether upon or after
termination or otherwise), supplemented or refinanced (including
by means of sales of debt securities to institutional investors)
in whole or in part from time to time.
Credit Facilities means, with respect to
Mariner or any of its Restricted Subsidiaries, one or more debt
facilities (including, without limitation, the Credit
Agreement), commercial paper facilities or Debt Issuances with
banks, investment banks, insurance companies, mutual funds,
other institutional lenders, institutional investors or any of
the foregoing providing for revolving credit loans, term loans,
receivables financing (including through the sale of receivables
to such lenders, other financiers or to special purpose entities
formed to borrow from (or sell such receivables to) such lenders
or other financiers against such receivables), letters of
credit, bankers acceptances, other borrowings or Debt
Issuances, in each case, as amended, restated, modified,
renewed, extended, refunded, replaced or refinanced (in each
case, without limitation as to amount), in whole or in part,
from time to time (including through one or more Debt Issuances)
and any agreements and related documents governing Indebtedness
or Obligations incurred to refinance amounts then outstanding or
permitted to be outstanding, whether or not with the original
administrative agent, lenders, investment banks, insurance
companies, mutual funds, other institutional lenders,
institutional investors or any of the foregoing and whether
provided under the original agreement, indenture or other
documentation relating thereto).
Debt Issuances means, with respect to Mariner
or any Restricted Subsidiary, one or more issuances after the
Issue Date of Indebtedness evidenced by notes, debentures, bonds
or other similar securities or instruments.
Default means any event that is, or with the
passage of time or the giving of notice or both would be, an
Event of Default.
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De Minimis Guaranteed Amount means a
principal amount of Indebtedness that does not exceed
$5.0 million.
Disqualified Stock means any Capital Stock
that, by its terms (or by the terms of any security into which
it is convertible, or for which it is exchangeable, in each
case, at the option of the holder of the Capital Stock), or upon
the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise,
or redeemable at the option of the holder of the Capital Stock,
in whole or in part, on or prior to the date that is
91 days after the date on which the notes mature; provided,
that only the portion of Capital Stock which so matures or is
mandatorily redeemable, or is so redeemable at the option of the
holder thereof prior to such date, will be deemed to be
Disqualified Stock. Notwithstanding the preceding sentence, any
Capital Stock that would constitute Disqualified Stock solely
because the holders of the Capital Stock have the right to
require Mariner to repurchase such Capital Stock upon the
occurrence of a change of control or an asset sale will not
constitute Disqualified Stock if the terms of such Capital Stock
provide that Mariner may not repurchase or redeem any such
Capital Stock pursuant to such provisions unless such repurchase
or redemption complies with the covenant described above under
the caption Certain Covenants
Restricted Payments. The amount of Disqualified Stock
deemed to be outstanding at any time for purposes of the
indenture will be the maximum amount that Mariner and its
Restricted Subsidiaries may become obligated to pay upon the
maturity of, or pursuant to any mandatory redemption provisions
of, such Disqualified Stock, exclusive of accrued dividends.
Dollar-Denominated Production Payments means
production payment obligations recorded as liabilities in
accordance with GAAP, together with all undertakings and
obligations in connection therewith.
Domestic Subsidiary means any Restricted
Subsidiary of Mariner that was formed under the laws of the
United States or any state of the United States or the District
of Columbia or that guarantees or otherwise provides direct
credit support for any Indebtedness of Mariner.
Equity Interests means Capital Stock and all
warrants, options or other rights to acquire Capital Stock (but
excluding any debt security that is convertible into, or
exchangeable for, Capital Stock).
Equity Offering means any public or private
sale of Capital Stock (other than Disqualified Stock) by Mariner
after the Issue Date.
Existing Indebtedness means Indebtedness of
Mariner and its Subsidiaries (other than Indebtedness under the
Credit Agreement) in existence on the date of the indenture,
until such amounts are repaid.
Fair Market Value means the value that would
be paid by a willing buyer to an unaffiliated willing seller in
a transaction not involving distress or necessity of either
party, determined in good faith by the Board of Directors of
Mariner (unless otherwise provided in the indenture), which
determination will be conclusive for all purposes under the
indenture.
Fixed Charge Coverage Ratio means with
respect to any specified Person for any period, the ratio of the
Consolidated Cash Flow of such Person for such period to the
Fixed Charges of such Person for such period. In the event that
the specified Person or any of its Restricted Subsidiaries
incurs, assumes, guarantees, repays, repurchases, redeems,
defeases or otherwise discharges any Indebtedness (other than
ordinary working capital borrowings) or issues, repurchases or
redeems preferred stock subsequent to the commencement of the
period for which the Fixed Charge Coverage Ratio is being
calculated and on or prior to the date on which the event for
which the calculation of the Fixed Charge Coverage Ratio is made
(the Calculation Date), then the Fixed Charge
Coverage Ratio will be calculated giving pro forma effect
to such incurrence, assumption, Guarantee, repayment,
repurchase, redemption, defeasance or other discharge of
Indebtedness, or such issuance, repurchase or redemption of
preferred stock, and the use of the proceeds therefrom, as if
the same had occurred at the beginning of the applicable
four-quarter reference period.
In addition, for purposes of calculating the Fixed Charge
Coverage Ratio:
(1) acquisitions that have been made by the specified
Person or any of its Restricted Subsidiaries, including through
mergers, consolidations or otherwise (including acquisitions of
assets used or useful in the Oil and Gas Business), or any
Person or any of its Restricted Subsidiaries acquired by the
specified
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Person or any of its Restricted Subsidiaries, and including any
related financing transactions and including increases in
ownership of Restricted Subsidiaries, during the four-quarter
reference period or subsequent to such reference period and on
or prior to the Calculation Date, shall be deemed to have
occurred on the first day of the four-quarter reference period
and the Consolidated Cash Flow for such reference period will be
calculated giving pro forma effect to any expense and
cost reductions that have occurred or, in the reasonable
judgment of the chief financial officer of Mariner, are
reasonably expected to occur (regardless of whether those
operating improvements or cost savings could then be reflected
in pro forma financial statements prepared in accordance
with
Regulation S-X
under the Securities Act or any other regulation or policy of
the SEC related thereto);
(2) the Consolidated Cash Flow attributable to discontinued
operations, as determined in accordance with GAAP, and
operations or businesses (and ownership interests therein)
disposed of prior to the Calculation Date, will be excluded;
(3) the Fixed Charges attributable to discontinued
operations, as determined in accordance with GAAP, and
operations or businesses (and ownership interests therein)
disposed of prior to the Calculation Date, will be excluded, but
only to the extent that the obligations giving rise to such
Fixed Charges will not be obligations of the specified Person or
any of its Restricted Subsidiaries following the Calculation
Date;
(4) any Person that is a Restricted Subsidiary on the
Calculation Date will be deemed to have been a Restricted
Subsidiary at all times during such four-quarter period;
(5) any Person that is not a Restricted Subsidiary on the
Calculation Date will be deemed not to have been a Restricted
Subsidiary at any time during such four-quarter period; and
(6) if any Indebtedness bears a floating rate of interest,
the interest expense on such Indebtedness will be calculated as
if the rate in effect on the Calculation Date had been the
applicable rate for the entire period (taking into account any
Hedging Obligation applicable to such Indebtedness if such
Hedging Obligation has a remaining term as at the Calculation
Date in excess of 12 months).
Fixed Charges means, with respect to any
specified Person for any period, the sum, without duplication,
of:
(1) the consolidated interest expense of such Person and
its Restricted Subsidiaries for such period, whether paid or
accrued (excluding any interest attributable to
Dollar-Denominated Production Payments but including, without
limitation, amortization of debt issuance costs and original
issue discount, noncash interest payments, the interest
component of any deferred payment obligations, the interest
component of all payments associated with Capital Lease
Obligations, imputed interest with respect to Attributable Debt,
commissions, discounts and other fees and charges incurred in
respect of letter of credit or bankers acceptance
financings), and net of the effect of all payments made or
received pursuant to Hedging Obligations in respect of interest
rates; plus (2) the consolidated interest expense of
such Person and its Restricted Subsidiaries that was capitalized
during such period; plus (3) any interest on
Indebtedness of another Person that is guaranteed by such Person
or one of its Restricted Subsidiaries or secured by a Lien on
assets of such Person or one of its Restricted Subsidiaries,
whether or not such Guarantee or Lien is called upon; plus
(4) all dividends, whether paid or accrued and whether
or not in cash, on any series of preferred stock of such Person
or any of its Restricted Subsidiaries, other than dividends on
Equity Interests payable solely in Equity Interests of Mariner
(other than Disqualified Stock) or to Mariner or a Restricted
Subsidiary of Mariner.
GAAP means generally accepted accounting
principles set forth in the opinions and pronouncements of the
Accounting Principles Board of the American Institute of
Certified Public Accountants and statements and pronouncements
of the Financial Accounting Standards Board or in such other
statements by such other entity as have been approved by a
significant segment of the accounting profession, which are in
effect from time to time. All ratios and computations based on
GAAP contained in the indenture will be computed in conformity
with GAAP.
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Guarantee means a guarantee other than by
endorsement of negotiable instruments for collection in the
ordinary course of business, direct or indirect, in any manner
including, without limitation, by way of a pledge of assets or
through letters of credit or reimbursement agreements in respect
thereof, of all or any part of any Indebtedness (whether arising
by virtue of partnership arrangements, or by agreements to
keep-well, to maintain financial statement conditions or
otherwise), or entered into for purposes of assuring in any
other manner the obligee of such Indebtedness of the payment
thereof or to protect such obligee against loss in respect
thereof (in whole or in part).
Guarantors means each of:
(1) Mariner LP LLC, Mariner Energy Resources, Inc. and
Mariner Energy Texas LP; and
(2) any other Subsidiary of Mariner that executes a Note
Guarantee in accordance with the provisions of the indenture,
and their respective successors and assigns, in each case, until
the Note Guarantee of such Person has been released in
accordance with the provisions of the indenture.
Hedging Obligations means, with respect to
any specified Person, the obligations of such Person under:
(1) interest rate swap agreements (whether from fixed to
floating or from floating to fixed), interest rate cap
agreements and interest rate collar agreements entered into with
one or more financial institutions and other arrangements or
agreements designed to protect the Person entering into the
agreement against fluctuations in interest rates with respect to
Indebtedness incurred and not for purposes of speculation;
(2) foreign exchange contracts and currency protection
agreements entered into with one or more financial institutions
and designed to protect the Person entering into the agreement
against fluctuations in currency exchange rates with respect to
Indebtedness incurred and not for purposes of speculation;
(3) any commodity futures contract, commodity option or
other similar agreement or arrangement designed to protect
against fluctuations in the price of commodities used, produced,
processed or sold by that Person or any of its Restricted
Subsidiaries at the time; and
(4) other agreements or arrangements designed to protect
such Person against fluctuations in interest rates, commodity
prices or currency exchange rates.
Hydrocarbons means oil, gas, casinghead gas,
drip gasoline, natural gasoline, condensate, distillate, liquid
hydrocarbons, gaseous hydrocarbons and all constituents,
elements or compounds thereof and products refined or processed
therefrom.
Indebtedness means, with respect to any
specified Person, any indebtedness of such Person (excluding
accrued expenses and trade payables), whether or not contingent:
(1) in respect of borrowed money;
(2) evidenced by bonds, notes, debentures or similar
instruments or letters of credit (or reimbursement agreements in
respect thereof);
(3) in respect of bankers acceptances;
(4) representing Capital Lease Obligations or Attributable
Debt in respect of sale and leaseback transactions;
(5) representing the balance deferred and unpaid of the
purchase price of any property due more than nine months after
such property is acquired;
(6) the principal component or liquidation preference of
all obligations of such Person with respect to the redemption,
repayment or other repurchase of any Disqualified Stock or, with
respect to any Subsidiary, any Preferred Stock (but excluding,
in each case, any accrued dividends);
(7) representing any Hedging Obligations;
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(8) the principal component of all Indebtedness of other
Persons secured by a Lien on any asset of such Person, whether
or not such Indebtedness is assumed by such Person; provided,
however, that the amount of such Indebtedness will be the
lesser of (a) the Fair Market Value of such asset at such
date of determination and (b) the amount of such
Indebtedness of such other Persons;
(9) the principal component of Indebtedness of other
Persons to the extent Guaranteed by such Person (including, with
respect to any Production Payment, any warranties or guarantees
of production or payment by such Person with respect to such
Production Payment, but excluding other contractual obligations
of such Person with respect to such Production Payment);
provided that the indebtedness described in
clauses (1), (2), (4) and (5) shall be included
in this definition of Indebtedness only if, and to the extent
that, the indebtedness described in such clauses would appear as
a liability upon a balance sheet of such Person prepared in
accordance with GAAP. Subject to clause (9) of the
preceding sentence, neither Dollar-Denominated Production
Payments nor Volumetric Production Payments shall be deemed to
be Indebtedness.
The amount of any Indebtedness outstanding as of any date will
be:
(1) the accreted value of the Indebtedness, in the case of
any Indebtedness issued with original issue discount;
(2) in the case of any Hedging Obligation, the termination
value of the agreement or arrangement giving rise to such
Hedging Obligation that would be payable by such Person at such
date; and
(3) the principal amount of the Indebtedness, together with
any interest on the Indebtedness that is more than 30 days
past due, in the case of any other Indebtedness.
The amount of Indebtedness of any Person at any date will be the
outstanding balance at such date of all unconditional
obligations as described above and the maximum liability, upon
the occurrence of the contingency giving rise to the obligation,
of any contingent obligations at such date.
In addition, Indebtedness of any Person shall
include Indebtedness described in the preceding paragraph that
would not appear as a liability on the balance sheet of such
Person if:
(1) such Indebtedness is the obligation of a partnership or
joint venture that is not a Restricted Subsidiary (a
Joint Venture);
(2) such Person or a Restricted Subsidiary of such Person
is a general partner of the Joint Venture
(a General Partner); and
(3) there is recourse, by contract or operation of law,
with respect to the payment of such Indebtedness to property or
assets by such Person or a Restricted Subsidiary of such Person;
and then such Indebtedness shall be included in an amount not to
exceed:
(a) the lesser of (i) the net assets of the General
Partner and (ii) the amount of such obligations to the
extent that there is recourse, by contract or operation of law,
to the property or assets of such Person or a Restricted
Subsidiary of such Person; or
(b) if less than the amount determined pursuant to
clause (a) immediately above, the actual amount of such
Indebtedness that is recourse to such Person or a Restricted
Subsidiary of such Person, if the Indebtedness is evidenced by a
writing and is for a determinable amount and the related
interest expense shall be included in Fixed Charges to the
extent actually paid by such Person or its Restricted
Subsidiaries.
Investment Grade Rating means a rating equal
to or higher than:
(1) Baa3 (or the equivalent) by Moodys; or
(2) BBB- (or the equivalent) by S&P, or, if either such
entity ceases to rate the notes for reasons outside of
Mariners control, the equivalent investment grade credit
rating from any other Rating Agency.
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Investment Grade Rating Event means the first
day on which the notes have an Investment Grade Rating from a
Rating Agency and no Default has occurred and is then continuing
under the indenture.
Investment Grade Securities means:
(1) securities issued or directly and fully guaranteed or
insured by the U.S. government or any agency or
instrumentality thereof (other than Cash Equivalents) and in
each case with maturities not exceeding tow years from the date
of acquisition;
(2) investments in any fund that invests exclusively in
investments of the type described in clause (1) which fund
may also hold immaterial amounts of cash pending investment
and/or
distribution; and
(3) corresponding instruments in countries other than the
United States customarily utilized for high quality investments
and in each case with maturities not exceeding two years from
the date of acquisition.
Investments means, with respect to any
Person, all direct or indirect investments by such Person in
other Persons (including Affiliates) in the forms of loans
(including Guarantees or other obligations, advances or capital
contributions (excluding endorsements of negotiable instruments
and documents in the ordinary course of business, and
commission, travel and similar advances to officers, employees
and consultants made in the ordinary course of business),
purchases or other acquisitions for consideration of
Indebtedness, Equity Interests or other securities, together
with all items that are or would be classified as investments on
a balance sheet prepared in accordance with GAAP. If Mariner or
any Restricted Subsidiary of Mariner sells or otherwise disposes
of any Equity Interests of any direct or indirect Subsidiary of
Mariner such that, after giving effect to any such sale or
disposition, such Person is no longer a Restricted Subsidiary of
Mariner, Mariner will be deemed to have made an Investment on
the date of any such sale or disposition equal to the Fair
Market Value of Mariners Investments in such Restricted
Subsidiary that were not sold or disposed of in an amount
determined as provided in the final paragraph of the covenant
described above under the caption Certain
Covenants Restricted Payments. The acquisition
by Mariner or any Subsidiary of Mariner of a Person that holds
an Investment in a third Person will be deemed to be an
Investment by Mariner or such Subsidiary in such third Person in
an amount equal to the Fair Market Value of the Investments held
by the acquired Person in such third Person in an amount
determined as provided in the final paragraph of the covenant
described above under the caption Certain
Covenants Restricted Payments. Except as
otherwise provided in the indenture, the amount of an Investment
will be determined at the time the Investment is made and
without giving effect to subsequent changes in value.
Issue Date means the date of original
issuance of the notes.
Lien means, with respect to any asset, any
mortgage, lien, pledge, charge, security interest or encumbrance
of any kind in respect of such asset, whether or not filed,
recorded or otherwise perfected under applicable law, including
any conditional sale or other title retention agreement, any
lease in the nature thereof, any option or other agreement to
sell or give a security interest in and any filing of any
financing statement under the Uniform Commercial Code (or
equivalent statutes) of any jurisdiction.
Material Change means an increase or decrease
(excluding changes that result solely from changes in prices and
changes resulting from the incurrence of previously estimated
future development costs) of more than 25% during a fiscal
quarter in the discounted future net revenues from proved crude
oil and natural gas reserves of Mariner and its Restricted
Subsidiaries, calculated in accordance with clause (1)(a)
of the definition of Adjusted Consolidated Net Tangible Assets;
provided, however, that the following will be excluded
from the calculation of Material Change:
(1) any acquisitions during the fiscal quarter of oil and
gas reserves that have been estimated by independent petroleum
engineers and with respect to which a report or reports of such
engineers exist; and
(2) any disposition of properties existing at the beginning
of such fiscal quarter that have been disposed of in compliance
with the covenant described under Repurchase
at the Option of Holders Assets Sales.
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Minority Interest means the percentage
interest represented by any shares of stock of any class of
Capital Stock of a Restricted Subsidiary of Mariner that are not
owned by Mariner or a Restricted Subsidiary of Mariner.
Moodys means Moodys Investors
Service, Inc. or any successor to the rating agency business
thereof.
Net Income means, with respect to any
specified Person, the net income (loss) of such Person,
determined in accordance with GAAP and before any reduction in
respect of preferred stock dividends, excluding, however:
(1) any gain (but not loss), together with any related
provision for taxes on such gain (but not loss), realized in
connection with: (a) any Asset Sale; or (b) the
disposition of any securities by such Person or any of its
Restricted Subsidiaries or the extinguishment of any
Indebtedness of such Person or any of its Restricted
Subsidiaries; and
(2) any extraordinary or nonrecurring gain (but not loss),
together with any related provision for taxes on such
extraordinary or nonrecurring gain (but not loss).
Net Proceeds means the aggregate cash
proceeds received by Mariner or any of its Restricted
Subsidiaries in respect of any Asset Sale (including, without
limitation, any cash received upon the sale or other disposition
of any non-cash consideration received in any Asset Sale), net
of:
(1) all legal, accounting, investment banking, title and
recording tax expenses, commissions and other fees and expense
incurred, and all Federal, state, provincial, foreign and local
taxes required to be paid or accrued as a liability under GAAP
(after taking into account any available tax credits or
deductions and any tax sharing agreements), as a consequence of
such Asset Sale;
(2) all payments made on any Indebtedness which is secured
by any assets subject to such Asset Sale, in accordance with the
terms of any Lien upon such assets, or which must by its terms,
or in order to obtain a necessary consent to such Asset Sale, or
by applicable law be repaid out of the proceeds from such Asset
Sale;
(3) all distributions and other payments required to be
made to holders of Minority Interests in Subsidiaries or joint
ventures as a result of such Asset Sale; and
(4) the deduction of appropriate amounts to be provided by
the seller as a reserve, in accordance with GAAP, or held in
escrow, in either case for adjustment in respect of the sale
price or for any liabilities associated with the assets disposed
of in such Asset Sale and retained by Mariner or any Restricted
Subsidiary after such Asset Sale.
Net Working Capital means (a) all
current assets of Mariner and its Restricted Subsidiaries except
current assets from commodity price risk management activities
arising in the ordinary course of business, less (b) all
current liabilities of Mariner and its Restricted Subsidiaries,
except current liabilities included in Indebtedness and any
current liabilities from commodity price risk management
activities arising in the ordinary course of business, in each
case as set forth in the consolidated financial statements of
Mariner prepared in accordance with GAAP (excluding any
adjustments made pursuant to FAS 133).
Non-Recourse Debt means Indebtedness:
(1) as to which neither Mariner nor any of its Restricted
Subsidiaries (a) provides credit support of any kind
(including any undertaking, agreement or instrument that would
constitute Indebtedness), (b) is directly or indirectly
liable as a guarantor or otherwise, or (c) constitutes the
lender;
(2) no default with respect to which (including any rights
that the holders of the Indebtedness may have to take
enforcement action against an Unrestricted Subsidiary) would
permit upon notice, lapse of time or both any holder of any
other Indebtedness of Mariner or any of its Restricted
Subsidiaries to declare a default on such other Indebtedness or
cause the payment of the Indebtedness to be accelerated or
payable prior to its Stated Maturity; and
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(3) as to which the lenders have been notified in writing
that they will not have any recourse to the stock or assets of
Mariner or any of its Restricted Subsidiaries, except as
contemplated by clause (26) of the definition of
Permitted Liens.
Note Guarantee means the Guarantee by each
Guarantor of Mariners Obligations under the indenture and
the notes, executed pursuant to the provisions of the indenture.
Obligations means any principal, interest,
penalties, fees, indemnifications, reimbursements, damages and
other liabilities payable under the documentation governing any
Indebtedness.
Oil and Gas Business means:
(1) the acquisition, exploration, exploitation,
development, production, operation and disposition of interests
in oil, gas and other Hydrocarbon properties;
(2) the gathering, marketing, treating, processing (but not
refining), storage, distribution, selling and transporting of
any production from such interests or properties;
(3) any business relating to exploration for or
development, production, exploitation, treatment, processing
(but not refining), storage, transportation or marketing of oil,
gas and other minerals and products produced in association
therewith; and
(4) any activity that is ancillary or complementary to or
necessary or appropriate for the activities described in
clauses (1) through (3) of this definition.
Permitted Acquisition Indebtedness means
Indebtedness or Disqualified Stock of Mariner or any of
Mariners Restricted Subsidiaries to the extent such
Indebtedness or Disqualified Stock was Indebtedness or
Disqualified Stock of:
(1) a Subsidiary prior to the date on which such Subsidiary
became a Restricted subsidiary; or
(2) a Person that was merged, consolidated or amalgamated
into Mariner or a Restricted Subsidiary, provided that on
the date such Subsidiary became a Restricted Subsidiary or the
date such Person was merged, consolidated and amalgamated into
Mariner or a Restricted Subsidiary, as applicable, after giving
pro forma effect thereto,
(a) the Restricted Subsidiary or Mariner, as applicable,
would be permitted to incur at least $1.00 of additional
Indebtedness pursuant to the Fixed Charge Coverage Ratio test
described under Certain Covenants
Incurrence of Indebtedness and Issuance of Preferred Stock,
(b) the Fixed Charge Coverage Ratio for the Restricted
Subsidiary or Mariner, as applicable, would be greater than the
Fixed Charge Coverage Ratio for such Restricted Subsidiary or
Mariner immediately prior to such transaction, or
(c) the Consolidated Net Worth of the Restricted Subsidiary
or Mariner, as applicable, would be greater than the
Consolidated Net Worth of such Restricted Subsidiary or Mariner
immediately prior to such transaction.
Permitted Business Investments means
Investments made in the ordinary course of, and of a nature that
is or shall have become customary in, the Oil and Gas Business,
including through agreements, transactions, interests or
arrangements that permit one to share risk or costs, comply with
regulatory requirements regarding local ownership or satisfy
other objectives customarily achieved through the conduct of the
Oil and Gas Business jointly with third parties, including
without limitation:
(1) direct or indirect ownership of crude oil, natural gas,
other restricted Hydrocarbon properties or any interest therein
or gathering, transportation, processing, storage or related
systems; and
(2) the entry into operating agreements, joint ventures,
processing agreements, working interests, royalty interests,
mineral leases, farm-in agreements, farm-out agreements,
development agreements, production sharing agreements, area of
mutual interest agreements, contracts for the sale,
transportation or exchange of crude oil and natural gas and
related Hydrocarbons and minerals, unitization agreements,
162
pooling arrangements, joint bidding agreements, service
contracts, partnership agreements (whether general or limited),
or other similar or customary agreements, transactions,
properties, interests or arrangements and Investments and
expenditures in connection therewith or pursuant thereto, in
each case made or entered into in the ordinary course of the Oil
and Gas Business, excluding, however, Investments in
corporations and publicly-traded limited partnerships.
Permitted Investments means:
(1) any Investment in Mariner or in a Restricted Subsidiary
of Mariner;
(2) any Investment in Cash Equivalents or Investment Grade
Securities;
(3) any Investment by Mariner or any Restricted Subsidiary
of Mariner in a Person, if as a result of such Investment:
(a) such Person becomes a Restricted Subsidiary of
Mariner; or
(b) such Person is merged, consolidated or amalgamated with
or into, or transfers or conveys substantially all of its assets
to, or is liquidated into, Mariner or a Restricted Subsidiary of
Mariner;
(4) any Investment made as a result of the receipt of
non-cash consideration from an Asset Sale that was made pursuant
to and in compliance with the covenant described above under the
caption Repurchase at the Option of
Holders Asset Sales;
(5) any acquisition of assets or Capital Stock solely in
exchange for the issuance of Equity Interests (other than
Disqualified Stock) of Mariner;
(6) any Investments received in compromise or resolution of
(A) obligations of trade creditors or customers that were
incurred in the ordinary course of business of Mariner or any of
its Restricted Subsidiaries, including pursuant to any plan of
reorganization or similar arrangement upon the bankruptcy or
insolvency of any trade creditor or customer; or
(B) litigation, arbitration or other disputes with Persons
who are not Affiliates;
(7) Investments represented by Hedging Obligations;
(8) advances to or reimbursements of employees for moving,
entertainment and travel expenses, drawing accounts and similar
expenditures in the ordinary course of business;
(9) loans or advances to employees in the ordinary course
of business or consistent with past practice not to exceed
$5.0 million in the aggregate at any one time outstanding;
(10) receivables owing to Mariner or any Restricted
Subsidiary created or acquired in the ordinary course of
business and payable or dischargeable in accordance with
customary trade terms; provided, however, that such trade
terms may include such concessionary trade terms as Mariner or
any such Restricted Subsidiary deems reasonable under the
circumstances;
(11) surety and performance bonds and workers
compensation, utility, lease, tax, performance and similar
deposits and prepaid expenses in the ordinary course of business;
(12) Guarantees of Indebtedness permitted under the
covenant contained under the caption Certain
Covenants Incurrence of Indebtedness and Issuance of
Preferred Stock;
(13) guarantees by Mariner or any of its Restricted
Subsidiaries of operating leases (other than Capital Lease
Obligations) or of other obligations that do not constitute
Indebtedness, in each case entered into by any Restricted
Subsidiary in the ordinary course of business;
(14) Investments of a Restricted Subsidiary acquired after
the Issue Date or of any entity merged into Mariner or merged
into or consolidated or amalgamated with a Restricted Subsidiary
in accordance with the covenant described under
Certain Covenants Merger,
Consolidated or Sale of Assets to the extent that such
Investments were not made in contemplation of or in connection
with such
163
acquisition, merger, consolidation or amalgamation and were in
existence on the date of such acquisition, merger or
consolidation;
(15) Permitted Business Investments;
(16) Investments received as a result of a foreclosure by
Mariner or any of its Restricted Subsidiaries with respect to
any secured Investment in default;
(17) Investments in any units of any oil and gas royalty
trust; and
(18) other Investments in any Person having an aggregate
Fair Market Value (measured on the date each such Investment was
made and without giving effect to subsequent changes in value),
when taken together with all other Investments made pursuant to
this clause (18) that are at the time outstanding not
to exceed the greater of (a) 1.00% of Adjusted Consolidated
Net Tangible Assets or (b) $10.0 million.
Permitted Liens means, with respect to any
Person:
(1) Liens securing Indebtedness incurred under the Credit
Facilities pursuant to the covenant described under the caption
Certain Covenants Incurrence of
Indebtedness and Issuance of Preferred Stock;
(2) Liens in favor of Mariner or the Guarantors;
(3) Liens on property of a Person existing at the time such
Person is merged with or into or consolidated or amalgamated
with Mariner or any Subsidiary of Mariner; provided that
such Liens were in existence prior to the contemplation of such
merger, consolidation or amalgamation and do not extend to any
assets other than those of the Person merged into or
consolidated or amalgamated with Mariner or the Subsidiary and
do not extend to any assets other than those of the Person
merged into or consolidated or amalgamated with Mariner or the
Subsidiary;
(4) Liens on property (including Capital Stock) existing at
the time of acquisition of the property by Mariner or any
Subsidiary of Mariner; provided that such Liens were in
existence prior to, such acquisition, and not incurred in
contemplation of, such acquisition;
(5) Liens existing on the Issue Date;
(6) Liens for taxes, assessments or governmental charges or
claims that are not yet delinquent or that are being contested
in good faith by appropriate proceedings promptly instituted and
diligently concluded; provided that any reserve or other
appropriate provision as is required in conformity with GAAP has
been made therefor;
(7) survey exceptions, easements or reservations of, or
rights of others for, licenses,
rights-of-way,
sewers, electric lines, telegraph and telephone lines and other
similar purposes, or zoning or other restrictions as to the use
of real property that were not incurred in connection with
Indebtedness and that do not in the aggregate materially
adversely affect the value of said properties or materially
impair their use in the operation of the business of such Person;
(8) leases or subleases granted to others that do not
materially interfere with the ordinary course of business of
Mariner and its Restricted Subsidiaries, taken as a whole;
(9) landlords, carriers, warehousemens,
mechanics, materialmens, repairmens or the
like Liens arising by contract or statute in the ordinary course
of business and with respect to amounts which are not yet
delinquent or are being contested in good faith by appropriate
proceedings;
(10) pledges or deposits made in the ordinary course of
business (A) in connection with leases, tenders, bids,
statutory obligations, surety or appeal bonds, government
contracts, performance bonds and similar obligations, or
(B) in connection with workers compensation,
unemployment insurance and other social security legislation;
(11) Liens encumbering property or assets under
construction arising from progress or partial payments by a
customer of Mariner or its Restricted Subsidiaries relating to
such property or assets;
164
(12) Liens in favor of customs and revenue authorities
arising as a matter of law to secure payments of customs duties
in connection with the importation of goods;
(13) any attachment or judgment Lien that does not
constitute an Event of Default;
(14) Liens created for the benefit of (or to secure) the
notes (or the Note Guarantees);
(15) Liens to secure any Permitted Refinancing Indebtedness
permitted to be incurred under the indenture; provided,
however, that:
(a) the new Lien shall be limited to all or part of the
same property and assets that secured or, under the written
agreements pursuant to which the original Lien arose, could
secure the original Lien (plus improvements and accessions to,
such property or proceeds or distributions thereof); and
(b) the Indebtedness secured by the new Lien is not
increased to any amount greater than the sum of (x) the
outstanding principal amount, or, if greater, committed amount,
of the Permitted Refinancing Indebtedness and (y) an amount
necessary to pay any fees and expenses, including premiums,
related to such renewal, refunding, refinancing, replacement,
defeasance or discharge; and
(16) Liens for the purpose of securing the payment of all
or a part of the purchase price of, or Capital Lease Obligations
with respect to, or the repair, improvement or construction cost
of, assets or property acquired or repaired, improved or
constructed in the ordinary course of business; provided that:
(a) the aggregate principal amount of Indebtedness secured
by such Liens is otherwise permitted to be incurred under the
indenture and does not exceed the cost of the assets or property
so acquired or repaired, improved or constructed plus fees and
expenses in connection therewith; and
(b) such Liens are created within 180 days of repair,
improvement, construction or acquisition of such assets or
property and do not encumber any other assets or property of
Mariner or any of its Restricted Subsidiaries other than such
assets or property and assets affixed or appurtenant thereto
(including improvements);
(17) Liens arising solely by virtue of any statutory or
common law provisions relating to bankers Liens, rights of
set-off or similar rights and remedies as to deposit accounts or
other funds maintained or deposited with a depositary
institution; provided that:
(a) such deposit account is not a dedicated cash collateral
account and is not subject to restrictions against access by
Mariner in excess of those set forth by regulations promulgated
by the Federal Reserve Board; and
(b) such deposit account is not intended by Mariner or any
Restricted Subsidiary to provide collateral to the depositary
institution;
(18) Liens arising from Uniform Commercial Code financing
statement filings regarding operating leases entered into by
Mariner and its Restricted Subsidiaries in the ordinary course
of business;
(19) Liens in respect of Production Payments and Reserve
Sales;
(20) Liens on pipelines and pipeline facilities that arise
by operation of law;
(21) farmout, carried working interest, joint operating,
unitization, royalty, sales and similar agreements relating to
the exploration or development of, or production from, oil and
gas properties entered into in the ordinary course of business;
(22) Liens reserved in oil and gas mineral leases for bonus
or rental payments and for compliance with the terms of such
leases;
(23) Liens arising under the indenture in favor of the
trustee for its own benefit and similar Liens in favor of other
trustees, agents and representatives arising under instruments
governing Indebtedness permitted to be incurred under the
indenture, provided, however, that such Liens are solely for the
benefit
165
of the trustees, agents or representatives in their capacities
as such and not for the benefit of the holders of the
Indebtedness;
(24) Liens securing Hedging Obligations of Mariner and its
Restricted Subsidiaries;
(25) Liens on and pledges of the Equity Interests of any
Unrestricted Subsidiary or any joint venture owned by Mariner or
any of its Restricted Subsidiary to the extent securing
Non-Recourse Debt of such Unrestricted Subsidiary or joint
venture;
(26) Liens upon specific items of inventory, receivables or
other goods or proceeds of Mariner or any of its Restricted
Subsidiaries securing such Persons obligations in respect
of bankers acceptances or receivables securitizations
issued or created for the account of such Person to facilitate
the purchase, shipment or storage of such inventory, receivables
or other goods or proceeds and permitted by the covenant
described under the caption Certain
Covenants Incurrence of Indebtedness and Issuance of
Preferred Stock; and
(27) Liens incurred in the ordinary course of business of
Mariner or any Subsidiary of Mariner with respect to Obligations
that do not exceed the greater of (a) $10.0 million at
any one time outstanding and (b) 1.00% of the Adjusted
Consolidated Net Tangible Assets determined as of the date of
the incurrence of such Obligations after giving pro forma effect
to such incurrence and the application of proceeds therefrom.
Permitted Refinancing Indebtedness means any
Indebtedness of Mariner or any of its Restricted Subsidiaries
issued in exchange for, or the net proceeds of which are used to
extend, renew, refund, refinance, replace, defease or discharge
other Indebtedness of Mariner or any of its Restricted
Subsidiaries (other than intercompany Indebtedness); provided
that:
(1) the principal amount (or accreted value, if applicable)
of such Permitted Refinancing Indebtedness does not exceed the
principal amount (or accreted value, if applicable) of the
Indebtedness extended, renewed, refunded, refinanced, replaced,
defeased or discharged (plus all accrued interest on the
Indebtedness and the amount of all fees and expenses, including
premiums, incurred in connection therewith);
(2) such Permitted Refinancing Indebtedness has a final
maturity date later than the final maturity date of, and has a
Weighted Average Life to Maturity equal to or greater than the
Weighted Average Life to Maturity of, the Indebtedness being
extended, renewed, refunded, refinanced, replaced, defeased or
discharged;
(3) if the Indebtedness being extended, renewed, refunded,
refinanced, replaced, defeased or discharged is subordinated in
right of payment to the notes, such Permitted Refinancing
Indebtedness has a final maturity date later than the final
maturity date of, and is subordinated in right of payment to,
the notes on terms at least as favorable to the holders of notes
as those contained in the documentation governing the
Indebtedness being extended, renewed, refunded, refinanced,
replaced, defeased or discharged; and
(4) such Indebtedness is incurred either by Mariner or by
the Restricted Subsidiary who is the obligor on the Indebtedness
being extended, renewed, refunded, refinanced, replaced,
defeased or discharged; provided, however, that a Restricted
Subsidiary that is also a Guarantor may guarantee Permitted
Refinancing Indebtedness incurred by Mariner, whether or not
such Restricted Subsidiary was an obligor or guarantor of the
Indebtedness being renewed, refunded, refinanced, replaced,
defeased or discharged.
Notwithstanding the foregoing, any Indebtedness incurred under
Credit Facilities pursuant to the covenant described above under
the caption Certain Covenants
Incurrence of Indebtedness and Issuance of Preferred Stock
shall be subject to the refinancing provisions of the definition
of Credit Facilities and not pursuant to the
requirements set forth in this definition of Permitted
Refinancing Indebtedness.
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Person means any individual, corporation,
partnership, joint venture, association, joint-stock company,
trust, unincorporated organization, limited liability company or
government or other entity.
Production Payments means, collectively,
Dollar-Denominated Production Payments and Volumetric Production
Payments.
Production Payments and Reserve Sales means
the grant or transfer by Mariner or a Restricted Subsidiary of
Mariner to any Person of a royalty, overriding royalty, net
profits interest, production payment (whether volumetric or
dollar denominated), partnership or other interest in oil and
gas properties, reserves or the right to receive all or a
portion of the production or the proceeds from the sale of
production attributable to such properties, including any such
grants or transfers pursuant to incentive compensation programs
on terms that are reasonably customary in the oil and gas
business for geologists, geophysicists and other providers of
technical services to Mariner or a Subsidiary of Mariner.
Rating Agency means each of S&P and
Moodys, or if S&P or Moodys or both shall not
make a rating on the notes publicly available, a nationally
recognized statistical rating agency or agencies, as the case
may be, selected by Mariner (as certified by a resolution of the
Board of Directors) which shall be substituted for S&P or
Moodys, or both, as the case may be.
Rating Decline means the occurrence of:
(1) a decrease of one or more gradations (including
gradations within Rating Categories as well as between Rating
Categories) in the rating of the notes by either Rating
Agency; or
(2) a withdrawal of the rating of the notes by either
Rating Agency; provided, however, that such decrease or
withdrawal occurs on, or within 90 days before or after the
earlier of (a) a Change of Control, (b) the date of
public notice of the occurrence of a Change of Control or
(c) public notice of the intention by Mariner to effect a
Change of Control (which period shall be extended so long as the
rating of the notes is under publicly announced consideration
for downgrade by either Rating Agency).
Restricted Investment means an Investment
other than a Permitted Investment.
Restricted Subsidiary of a Person means any
Subsidiary of the referent Person that is not an Unrestricted
Subsidiary.
S&P means Standard & Poors
Ratings Services, a division of The McGraw-Hill Companies, Inc.
Senior Debt means:
(1) all Indebtedness of Mariner or any of its Restricted
Subsidiaries outstanding under Credit Facilities and all Hedging
Obligations with respect thereto;
(2) any other Indebtedness of Mariner or any of its
Restricted Subsidiaries permitted to be incurred under the terms
of the indenture, unless the instrument under which such
Indebtedness is incurred expressly provides that it is
subordinated in right of payment to the notes or any note
Guarantee; and
(3) all Obligations with respect to the items listed in the
preceding clauses (1) and (2). Notwithstanding anything to
the contrary in the preceding sentence, Senior Debt will not
include:
(a) any intercompany Indebtedness of Mariner or any of its
Subsidiaries to Mariner or any of its Affiliates; or
(b) any Indebtedness that is incurred in violation of the
indenture.
For the avoidance of doubt, Senior Debt will not
include any trade payables or taxes owed or owing by Mariner or
any Restricted Subsidiary.
Significant Subsidiary means any Subsidiary
that would be a significant subsidiary as defined in
Article 1,
Rule 1-02
of
Regulation S-X,
promulgated pursuant to the Securities Act, as such Regulation
is in effect on the date of the indenture.
Special Interest means all liquidated damages
then owing pursuant to the registration rights agreement.
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Stated Maturity means, with respect to any
installment of interest or principal on any series of
Indebtedness, the date on which the payment of interest or
principal was scheduled to be paid in the documentation
governing such Indebtedness as of the date of the indenture, and
will not include any contingent obligations to repay, redeem or
repurchase any such interest or principal prior to the date
originally scheduled for the payment thereof.
Subordinated Obligation means any
Indebtedness of Mariner (whether outstanding on the Issue Date
or thereafter incurred) which is subordinate or junior in right
of payment to the notes pursuant to a written agreement or any
Indebtedness of a Guarantor (whether outstanding on the Issue
Date or thereafter incurred) which is subordinate or junior in
right of payment to the Note Guarantee pursuant to a written
agreement, as the case may be.
Subsidiary means, with respect to any
specified Person:
(1) any corporation, association or other business entity
of which more than 50% of the total voting power of shares of
Capital Stock entitled (without regard to the occurrence of any
contingency and after giving effect to any voting agreement or
stockholders agreement that effectively transfers voting
power) to vote in the election of directors, managers or
trustees of the corporation, association or other business
entity is at the time owned or controlled, directly or
indirectly, by that Person or one or more of the other
Subsidiaries of that Person (or a combination thereof); and
(2) any partnership (a) the sole general partner or
the managing general partner of which is such Person or a
Subsidiary of such Person or (b) the only general partners
of which are that Person or one or more Subsidiaries of that
Person (or any combination thereof).
Unrestricted Subsidiary means any Subsidiary
of Mariner that is designated by the Board of Directors of
Mariner as an Unrestricted Subsidiary pursuant to a resolution
of the Board of Directors, but only to the extent that such
Subsidiary:
(1) has no Indebtedness other than Non-Recourse Debt;
(2) except as permitted by the covenant described above
under the caption Certain
Covenants Transactions with Affiliates, is not
party to any agreement, contract, arrangement or understanding
with Mariner or any Restricted Subsidiary of Mariner unless the
terms of any such agreement, contract, arrangement or
understanding are no less favorable to Mariner or such
Restricted Subsidiary than those that might be obtained at the
time from Persons who are not Affiliates of Mariner;
(3) is a Person with respect to which neither Mariner nor
any of its Restricted Subsidiaries has any direct or indirect
obligation (a) to subscribe for additional Equity Interests
or (b) to maintain or preserve such Persons financial
condition or to cause such Person to achieve any specified
levels of operating results; and
(4) has not guaranteed or otherwise directly or indirectly
provided credit support for any Indebtedness of Mariner or any
of its Restricted Subsidiaries, other than pursuant to a Note
Guarantee.
Volumetric Production Payments means
production payment obligations recorded as deferred revenue in
accordance with GAAP, together with all related undertakings and
obligations.
Voting Stock of any specified Person as of
any date means the Capital Stock of such Person that is at the
time entitled to vote in the election of the Board of Directors
of such Person.
Weighted Average Life to Maturity means, when
applied to any Indebtedness at any date, the number of years
obtained by dividing:
(1) the sum of the products obtained by multiplying
(a) the amount of each then remaining installment, sinking
fund, serial maturity or other required payments of principal,
including payment at final maturity, in respect of the
Indebtedness, by (b) the number of years (calculated to the
nearest
one-twelfth)
that will elapse between such date and the making of such
payment; by (2) the then outstanding principal
amount of such Indebtedness.
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MATERIAL
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following summary of the material U.S. federal income
tax considerations relevant to the exchange of new notes for old
notes pursuant to the exchange offer does not purport to be a
complete analysis of all potential tax effects. The discussion
is based upon the Internal Revenue Code of 1986, as amended,
Treasury Regulations, Internal Revenue Service rulings and
pronouncements and judicial decisions now in effect, all of
which may be subject to change at any time by legislative,
judicial or administrative action. These changes may be applied
retroactively in a manner that could adversely affect a holder
of new notes. The description does not consider the effect of
any applicable foreign, state, local or other tax laws or estate
or gift tax considerations.
The exchange of new notes for old notes pursuant to the exchange
offer will not be a taxable exchange for U.S. federal
income tax purposes. A holder will not recognize any taxable
gain or loss as a result of the exchange and will have the same
tax basis and holding period in the new notes as the holder had
in the old notes immediately before the exchange.
PLAN OF
DISTRIBUTION
Each broker-dealer that receives new notes for its own account
pursuant to the exchange offer must acknowledge that it will
deliver a prospectus in connection with any resale of new notes.
This prospectus, as it may be amended or supplemented from time
to time, may be used by a broker-dealer in connection with
resales of new notes received in exchange for old notes where
such old notes were acquired as a result of market-making
activities or other trading activities. In addition, until
January 8, 2007 (90 days after the date of this
prospectus), all dealers effecting transactions in the new
notes, whether or not participating in this distribution, may be
required to deliver a prospectus. This requirement is in
addition to the obligation of dealers to deliver a prospectus
when acting as underwriters and with respect to their unsold
allotments or subscriptions.
We will not receive any proceeds from any sale of new notes by
broker-dealers. New notes received by broker-dealers for their
own account pursuant to the exchange offer may be sold from time
to time in one or more transactions:
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in the
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in negotiated transactions,
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through the writing of options on the new notes or a combination
of such methods of resale,
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at market prices prevailing at the time of resale,
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at prices related to such prevailing market prices, or
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at negotiated prices.
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Any such resale may be made directly to purchasers or to or
through brokers or dealers who may receive compensation in the
form of commissions or concessions from any such broker-dealer
or the purchasers of any such new notes.
Any broker-dealer that resells new notes received for its own
account pursuant to the exchange offer and any broker or dealer
that participates in a distribution of such new notes may be
deemed to be an underwriter within the meaning of
the Securities Act and any profit on any such resale of new
notes and any commission on concessions received by any such
persons may be deemed to be underwriting compensation under the
Securities Act. The letter of transmittal states that, by
acknowledging that it will deliver a prospectus and by
delivering a prospectus, a broker-dealer will not be deemed to
admit that it is an underwriter within the meaning
of the Securities Act. The letter of transmittal also states
that any holder participating in this exchange offer will have
no arrangements or understanding with any person to participate
in the distribution of the old notes or the new notes within the
meaning of the Securities Act.
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For a period of 90 days after the exchange date, we will
promptly send additional copies of this prospectus and any
amendment or supplement to this prospectus to any broker dealer
that requests such documents in the letter of transmittal. We
have agreed to pay all expenses incident to the exchange offer
(including the expenses of one counsel for the holders of the
old notes) other than certain taxes and commissions or
concessions of any brokers or dealers, and will indemnify the
holders of the old notes (including any broker dealers) against
certain liabilities, including liabilities under the Securities
Act.
LEGAL
MATTERS
The validity of the notes and the validity of the subsidiary
guarantees offered hereby will be passed upon for us by Baker
Botts L.L.P.
EXPERTS
The financial statements of Mariner Energy, Inc. as of
December 31, 2005 and 2004 and for the year ended
December 31, 2005, for the period from January 1, 2004
through March 2, 2004 (Pre-merger), for the period from
March 3, 2004 through December 31, 2004 (Post-merger),
and for the year ended December 31, 2003 (Pre-merger)
included in this prospectus have been audited by
Deloitte & Touche LLP, an independent registered public
accounting firm, as stated in their report (which report
expresses an unqualified opinion and includes explanatory
paragraphs relating to a change in method of accounting for
asset retirement obligations in 2003 and the merger of Mariner
Energy, Inc.s parent company on March 2,
2004) appearing herein and is included in reliance upon the
report of such firm given upon their authority as experts in
accounting and auditing.
The Statements of Revenues and Direct Operating expenses of the
Forest Gulf of Mexico operations for each of the years in the
three-year period ended December 31, 2005 have been
included herein and in the registration statement in reliance
upon the report of KPMG LLP, independent registered public
accounting firm, appearing elsewhere herein, and upon the
authority of said firm as experts in accounting and auditing.
The information included in this prospectus regarding estimated
quantities of proved reserves, the future net revenues from
those reserves and their present value is based, in part, on
estimates of the proved reserves and present values of proved
reserves of Mariner as of December 31, 2003, 2004 and 2005
and prepared by or derived from estimates prepared by Ryder
Scott Company, L.P., independent petroleum engineers. These
estimates are included in this prospectus in reliance upon the
authority of the firm as experts in these matters.
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GLOSSARY
OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the
oil and gas industry terms used in this prospectus. The
definitions of proved developed reserves, proved reserves and
proved undeveloped reserves have been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definitions of those terms can be viewed on the
website at
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
3-D
seismic. (Three-Dimensional Seismic Data) Geophysical data
that depicts the subsurface strata in three dimensions.
3-D seismic
data typically provides a more detailed and accurate
interpretation of the subsurface strata than two dimensional
seismic data.
Appraisal well. A well drilled several spacing
locations away from a producing well to determine the boundaries
or extent of a productive formation and to establish the
existence of additional reserves.
bbl. One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
Block. A block depicted on the Outer
Continental Shelf Leasing and Official Protraction Diagrams
issued by the U.S. Minerals Management Service or a similar
depiction on official protraction or similar diagrams issued by
a state bordering on the Gulf of Mexico.
Btu or British Thermal Unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
Completion. The installation of permanent
equipment for the production of oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
Condensate. Liquid hydrocarbons associated
with the production of a primarily natural gas reserve.
Deep shelf well. A well drilled on the outer
continental shelf to subsurface depths greater than
15,000 feet.
Deepwater. Depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service).
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development well. A well drilled within the
proved boundaries of an oil or natural gas reservoir with the
intention of completing the stratigraphic horizon known to be
productive.
Dry hole. A well found to be incapable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production
expenses and taxes.
Dry hole costs. Costs incurred in drilling a
well, assuming a well is not successful, including plugging and
abandonment costs.
Exploitation. Ordinarily considered to be a
form of development within a known reservoir.
Exploratory well. A well drilled to find and
produce oil or gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement under which
the owner of a working interest in an oil or gas lease assigns
the working interest or a portion of the working interest to
another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells
in order to earn its interest in the
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acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a
farm-in while the interest transferred by the
assignor is a farm-out.
Field. An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
Infill well. A well drilled between known
producing wells to better exploit the reservoir.
Lease operating expenses. The expenses of
lifting oil or gas from a producing formation to the surface,
and the transportation and marketing thereof, constituting part
of the current operating expenses of a working interest, and
also including labor, superintendence, supplies, repairs,
short-lived assets, maintenance, allocated overhead costs, ad
valorem taxes and other expenses incidental to production, but
not including lease acquisition or drilling or completion
expenses.
Mbbls. Thousand barrels of crude oil or other
liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
MMBls. Million barrels of crude oil or other
liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
Net revenue interest. An interest in all oil
and natural gas produced and saved from, or attributable to, a
particular property, net of all royalties, overriding royalties,
net profits interests, carried interests, reversionary interests
and any other burdens to which the persons interest is
subject.
Payout. Generally refers to the recovery by
the incurring party to an agreement of its costs of drilling,
completing, equipping and operating a well before another
partys participation in the benefits of the well commences
or is increased to a new level.
PV10 or present value of estimated future net
revenues. An estimate of the present value of the
estimated future net revenues from proved oil and gas reserves
at a date indicated after deducting estimated production and ad
valorem taxes, future capital costs and operating expenses, but
before deducting any estimates of federal income taxes. The
estimated future net revenues are discounted at an annual rate
of 10%, in accordance with the Securities and Exchange
Commissions practice, to determine their present
value. The present value is shown to indicate the effect
of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties.
Estimates of future net revenues are made using oil and natural
gas prices and operating costs at the date indicated and held
constant for the life of the reserves.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Prospect. A specific geographic area which,
based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery
of commercial hydrocarbons.
Proved developed non-producing
reserves. Proved developed reserves expected to
be recovered from zones behind casing in existing wells.
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Proved developed producing reserves. Proved
developed reserves that are expected to be recovered from
completion intervals currently open in existing wells and
capable of production to market.
Proved developed reserves. Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods. This definition of
proved developed reserves has been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Proved reserves. The estimated quantities of
crude oil, natural gas and natural gas liquids that geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions. This definition of proved
reserves has been abbreviated from the applicable definitions
contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Proved undeveloped reserves. Proved reserves
that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major
expenditure is required for recompletion. This definition of
proved undeveloped reserves has been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
Shelf. Areas in the Gulf of Mexico with depths
less than 1,300 feet. Our shelf area and operations also
includes a small amount of properties and operations in the
onshore and bay areas of the Gulf Coast.
Subsea tieback. A method of completing a
productive well by connecting its wellhead equipment located on
the sea floor by means of control umbilical and flow lines to an
existing production platform located in the vicinity.
Subsea trees. Wellhead equipment installed on
the ocean floor.
Undeveloped acreage. Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or gas
regardless of whether or not such acreage contains proved
reserves.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
173
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
MARINER ENERGY, INC.
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-26
|
|
|
|
|
F-27
|
|
|
|
|
F-28
|
|
|
|
|
F-29
|
|
|
|
|
F-30
|
|
|
|
|
F-31
|
|
FOREST GULF OF MEXICO
OPERATIONS
|
|
|
|
|
|
|
|
F-62
|
|
|
|
|
F-63
|
|
|
|
|
F-64
|
|
F-1
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands except
|
|
|
|
share data)
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,656
|
|
|
$
|
4,556
|
|
Receivables, net of allowances of
$190 at June 30, 2006 and $500 at December 31, 2005,
respectively
|
|
|
124,806
|
|
|
|
84,109
|
|
Insurance receivables
|
|
|
61,798
|
|
|
|
4,542
|
|
Prepaid seismic
|
|
|
16,327
|
|
|
|
6,542
|
|
Prepaid expenses and other
|
|
|
28,509
|
|
|
|
15,666
|
|
Deferred tax asset
|
|
|
10,215
|
|
|
|
26,017
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
247,311
|
|
|
|
141,432
|
|
Property and
Equipment:
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost
method: Proved
|
|
|
1,901,992
|
|
|
|
574,725
|
|
Unproved, not subject to
amortization
|
|
|
211,260
|
|
|
|
40,176
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,113,252
|
|
|
|
614,901
|
|
Other property and equipment
|
|
|
13,598
|
|
|
|
11,048
|
|
Accumulated depreciation,
depletion and amortization
|
|
|
(213,241
|
)
|
|
|
(110,006
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
1,913,609
|
|
|
|
515,943
|
|
Goodwill
|
|
|
261,472
|
|
|
|
|
|
Other Assets, Net of
Amortization
|
|
|
34,716
|
|
|
|
8,161
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
2,457,108
|
|
|
$
|
665,536
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
57,674
|
|
|
$
|
37,530
|
|
Accrued liabilities
|
|
|
275,414
|
|
|
|
123,689
|
|
Accrued interest
|
|
|
4,828
|
|
|
|
614
|
|
Derivative liability
|
|
|
21,400
|
|
|
|
42,173
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
359,316
|
|
|
|
204,006
|
|
Long-Term
Liabilities:
|
|
|
|
|
|
|
|
|
Abandonment liability
|
|
|
188,764
|
|
|
|
38,176
|
|
Deferred income tax
|
|
|
252,562
|
|
|
|
25,886
|
|
Derivative liability
|
|
|
4,262
|
|
|
|
21,632
|
|
Long term debt, revolving credit
facility
|
|
|
157,000
|
|
|
|
152,000
|
|
Long term debt, senior unsecured
notes
|
|
|
300,000
|
|
|
|
|
|
Note payable
|
|
|
|
|
|
|
4,000
|
|
Other long-term liabilities
|
|
|
11,000
|
|
|
|
6,500
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
913,588
|
|
|
|
248,194
|
|
Commitments and Contingencies
(see Note 8)
|
|
|
|
|
|
|
|
|
Stockholders
Equity:
|
|
|
|
|
|
|
|
|
Common stock, $.0001 par
value; 180,000,000 shares authorized,
86,243,379 shares issued and outstanding at June 30,
2006; 70,000,000 shares authorized, 35,615,400 shares
issued and outstanding at December 31, 2005
|
|
|
9
|
|
|
|
4
|
|
Preferred stock, $.0001 par
value; 20,000,000 shares authorized, no shares issued and
outstanding at June 30, 2006 and December 31, 2005
|
|
|
|
|
|
|
|
|
Additional
paid-in-capital
|
|
|
1,055,412
|
|
|
|
160,705
|
|
Accumulated other comprehensive
loss
|
|
|
(7,151
|
)
|
|
|
(41,473
|
)
|
Accumulated retained earnings
|
|
|
135,934
|
|
|
|
94,100
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,184,204
|
|
|
|
213,336
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND
STOCKHOLDERS EQUITY
|
|
$
|
2,457,108
|
|
|
$
|
665,536
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements
F-2
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
Six-Months Ended June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
87,726
|
|
|
$
|
38,435
|
|
Gas sales
|
|
|
158,576
|
|
|
|
67,090
|
|
Other revenues
|
|
|
1,623
|
|
|
|
2,058
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
247,925
|
|
|
|
107,583
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
37,567
|
|
|
|
13,194
|
|
Transportation expense
|
|
|
2,277
|
|
|
|
1,501
|
|
General and administrative expense
|
|
|
17,473
|
|
|
|
15,400
|
|
Depreciation, depletion and
amortization
|
|
|
109,806
|
|
|
|
31,054
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
167,123
|
|
|
|
61,149
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
80,802
|
|
|
|
46,434
|
|
Interest:
|
|
|
|
|
|
|
|
|
Income
|
|
|
249
|
|
|
|
561
|
|
Expense, net of amounts capitalized
|
|
|
(14,668
|
)
|
|
|
(3,567
|
)
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
66,383
|
|
|
|
43,428
|
|
Provision for income
taxes
|
|
|
(24,549
|
)
|
|
|
(14,808
|
)
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
41,834
|
|
|
$
|
28,620
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
Net income per share
basic
|
|
$
|
0.62
|
|
|
$
|
0.90
|
|
Net income per share
diluted
|
|
$
|
0.62
|
|
|
$
|
0.89
|
|
Weighted average shares
outstanding basic
|
|
|
67,244,331
|
|
|
|
31,975,754
|
|
Weighted average shares
outstanding diluted
|
|
|
67,829,117
|
|
|
|
32,241,159
|
|
The accompanying notes are an integral part of these
consolidated financial statements
F-3
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
For the Six-Months
|
|
|
|
Ended June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Operating Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
41,834
|
|
|
$
|
28,620
|
|
Adjustments to reconcile net
income to net cash provided by operating activities: Deferred
income tax
|
|
|
24,549
|
|
|
|
20,325
|
|
Depreciation, depletion and
amortization
|
|
|
111,851
|
|
|
|
31,626
|
|
Stock compensation expense
|
|
|
7,891
|
|
|
|
9,496
|
|
Net realized loss on derivative
contracts acquired
|
|
|
3,548
|
|
|
|
|
|
Changes in operating assets and
liabilities:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
13,382
|
|
|
|
(17,825
|
)
|
Insurance receivable
|
|
|
(42,128
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
(1,134
|
)
|
|
|
(249
|
)
|
Other assets
|
|
|
(5,150
|
)
|
|
|
|
|
Accounts payable and accrued
liabilities
|
|
|
(58,548
|
)
|
|
|
685
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
96,095
|
|
|
|
72,678
|
|
|
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
Additions to properties and
equipment
|
|
|
(185,997
|
)
|
|
|
(98,724
|
)
|
Proceeds from property conveyances
|
|
|
2,012
|
|
|
|
18
|
|
Purchase price adjustment
|
|
|
(20,808
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(204,793
|
)
|
|
|
(98,706
|
)
|
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
|
|
Repayment of term note
|
|
|
(4,000
|
)
|
|
|
(6,000
|
)
|
Credit facility borrowings
(repayments), net
|
|
|
5,000
|
|
|
|
(10,000
|
)
|
Debt and working capital acquired
from Forest Energy Resources, Inc.
|
|
|
(176,200
|
)
|
|
|
|
|
Proceeds from note offering
|
|
|
300,000
|
|
|
|
|
|
Deferred offering costs
|
|
|
(12,129
|
)
|
|
|
|
|
Net realized loss on derivative
contracts acquired
|
|
|
(3,548
|
)
|
|
|
|
|
Proceeds from private equity
offering
|
|
|
|
|
|
|
44,659
|
|
Capital contribution from
affiliates
|
|
|
|
|
|
|
2,879
|
|
Proceeds from exercise of stock
options
|
|
|
675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
109,798
|
|
|
|
31,538
|
|
|
|
|
|
|
|
|
|
|
Increase in Cash and Cash
Equivalents
|
|
|
1,100
|
|
|
|
5,510
|
|
Cash and Cash Equivalents at
Beginning of Period
|
|
|
4,556
|
|
|
|
2,541
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at
End of Period
|
|
$
|
5,656
|
|
|
$
|
8,051
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements
F-4
MARINER
ENERGY, INC.
Unaudited
|
|
1.
|
Summary
of Significant Accounting Policies
|
Operations Mariner Energy, Inc.
(Mariner or the Company) is an
independent oil and gas exploration, development and production
company with principal operations in the Gulf of Mexico, both
shelf and deepwater, and in West Texas. Effective March 2,
2006, a subsidiary of the Company completed a merger transaction
with Forest Energy Resources, Inc. pursuant to which the Company
acquired the Gulf of Mexico operations of Forest Oil
Corporation. Please see Note 3, Acquisitions
for further discussion of this transaction. Unless otherwise
indicated, references to Mariner, the
Company, we, our, ours
and us refer to Mariner Energy, Inc. and its
subsidiaries collectively.
Interim Financial Statements The accompanying
unaudited consolidated financial statements have been prepared
without audit, pursuant to the rules and regulations of the
Securities and Exchange Commission (SEC). Certain
information and footnote disclosures normally included in
financial statements prepared in accordance with accounting
principles generally accepted in the United States of America
(GAAP) have been condensed or omitted, although we
believe that the disclosures contained herein are adequate to
make the information presented not misleading. In the opinion of
management, all adjustments (consisting of normal recurring
accruals) considered necessary for a fair presentation have been
included. Operating results for interim periods are not
necessarily indicative of the results that may be expected for
the entire year. Our balance sheet at December 31, 2005 is
derived from the December 31, 2005 audited financial
statements, but does not include all disclosures required by
GAAP. These unaudited consolidated financial statements included
herein should be read in conjunction with the Financial
Statements and Notes included in the Companys Annual
Report on
Form 10-K
for the year ended December 31, 2005.
Use of Estimates The preparation of the
consolidated financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of
the financial statements and the reported amounts of revenues
and expenses during the reporting periods. Our most significant
financial estimates are based on remaining proved natural gas
and oil reserves. Estimates of proved reserves are key
components of our depletion rate for natural gas and oil
properties, our unevaluated properties and our full cost ceiling
test. In addition, estimates are used in computing taxes,
preparing accruals of operating costs and production revenues,
asset retirement obligations, fair value and effectiveness of
derivative instruments and fair value of stock options and the
related compensation expense. Because of the inherent nature of
the estimation process, actual results could differ materially
from these estimates.
Principles of Consolidation Our consolidated
financial statements as of June 30, 2006 and
December 31, 2005 and for the six-month periods ended
June 30, 2006 and 2005 include our accounts and the
accounts of our wholly-owned subsidiaries. All significant
inter-company balances and transactions have been eliminated.
Reclassifications Certain prior year amounts
have been reclassified to conform to current year presentation.
Income Tax Provision Our provision for taxes
includes both state and federal taxes. In May 2006, the State of
Texas enacted substantial changes to its tax structure beginning
in 2007 by implementing a new margin tax of 1% to be imposed on
revenues less certain costs, as specified in the legislation.
During the second quarter of 2006, we increased our provision by
an additional $1.3 million to provide for deferred taxes to
the State of Texas under the newly enacted state margin tax.
Recent Accounting Pronouncements In September
2005, the Emerging Issues Task Force (EITF) reached
a consensus on Issue
No. 04-13,
Accounting for Purchases and Sales of Inventory with the
Same Counterparty. EITF
Issue 04-13
requires that purchases and sales of inventory with the same
counterparty in the same line of business should be accounted
for as a single non-monetary exchange, if entered into
F-5
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
incontemplation of one another. The consensus is effective for
inventory arrangements entered into, modified or renewed in
interim or annual reporting periods beginning after
March 15, 2006. We adopted EITF
Issue 04-13
on April 1, 2006 and it did not have a material impact on
our consolidated financial position, results of operations or
cash flows.
In July 2006, the FASB issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income
Taxes. FIN No. 48 clarifies
SFAS No. 109, Accounting for Income Taxes, and
requires us to evaluate our tax positions for all jurisdictions
and all years where the statute of limitations has not expired.
FIN No. 48 requires companies to meet a
more-likely-than-not threshold (i.e. greater than a
50 percent likelihood of being sustained under examination)
prior to recording a benefit for their tax positions.
Additionally, for tax positions meeting this
more-likely-than-not threshold, the amount of
benefit is limited to the largest benefit that has a greater
than 50 percent probability of being realized upon ultimate
settlement. The cumulative effect of applying the provisions of
the new interpretation will be recorded as an adjustment to the
beginning balance of retained earnings, or other components of
stockholders equity, as appropriate, in the period of
adoption. We will adopt the provisions of this interpretation
effective January 1, 2007, and are currently evaluating the
impact, if any, that this interpretation will have on our
financial statements.
|
|
2.
|
Related
Party Transactions
|
Organization and Ownership of the Company On
March 2, 2004, Mariner Energy LLC, the Companys
indirect parent, merged with a subsidiary of MEI Acquisitions
Holdings, LLC, an affiliate of the private equity funds
Carlyle/Riverstone Global Energy and Power Fund II, L.P.
and ACON Investments LLC (the Merger). Prior to the
Merger, Joint Energy Development Investments Limited Partnership
(JEDI), which was an indirect wholly-owned
subsidiary of Enron Corp. (Enron), owned
approximately 96% of the common stock of Mariner Energy LLC. In
the Merger, all the shares of common stock in Mariner Energy LLC
were converted into the right to receive cash and certain other
consideration. As a result, JEDI no longer owned any interest in
Mariner Energy LLC, and the Company ceased to be affiliated with
JEDI or Enron.
Until February 10, 2005, the Company was a wholly-owned
subsidiary of Mariner Holdings, Inc., which was a wholly-owned
subsidiary of Mariner Energy LLC. On February 10, 2005, in
anticipation of the private placement by the Company and its
sole stockholder of an aggregate 31,452,500 shares of the
Companys common stock in March 2005 (the Private
Equity Placement), Mariner Holdings, Inc. and Mariner
Energy LLC were merged into the Company and ceased to exist. The
mergers of Mariner Holdings, Inc. and Mariner Energy LLC into
the Company had no operational or financial impact on the
Company; however, intercompany receivables of $0.2 million
and $2.9 million in cash held by the affiliates were
transferred to the Company in February 2005 and accounted for as
additional paid in capital. In the Private Equity Placement, the
Company sold 16,350,000 shares of its common stock and its
sole stockholder sold 15,102,500 shares of the
Companys common stock. The Companys net proceeds in
the Private Equity Placement were $212.9 million, before
offering costs of $2.2 million, of which
$166.0 million was paid to its sole stockholder to redeem
12,750,000 shares of the Companys common stock in
March 2005.
The Company was previously party to management agreements with
two affiliates of its former parent company. These agreements
provided for the payment by Mariner Energy LLC of an aggregate
of $2.5 million to the affiliates in connection with the
provision of management services. Such payments have been made.
Mariner Energy LLC also entered into monitoring agreements with
two affiliates of its former parent, providing for the payment
by Mariner Energy LLC of an aggregate of one percent of its
annual EBITDA to the affiliates in connection with certain
monitoring activities. Under the terms of the monitoring
agreements, the affiliates provided financial advisory services
in connection with the ongoing operations of Mariner. Effective
February 7, 2005, these contracts were terminated in
consideration of lump sum cash payments by Mariner totaling
$2.3 million. The Company recorded the termination payments
as general and administrative expenses for the quarter ended
March 31, 2005.
F-6
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Forest Gulf of Mexico Operations On
March 2, 2006, a subsidiary of the Company completed a
merger transaction with Forest Energy Resources, Inc. (the
Forest Transaction). Prior to the consummation of
the merger, Forest Oil Corporation (Forest)
transferred and contributed the assets of, and certain
liabilities associated with, its offshore Gulf of Mexico
operations to Forest Energy Resources, Inc. Immediately prior to
the merger, Forest distributed all of the outstanding shares of
Forest Energy Resources, Inc. to Forest shareholders on a pro
rata basis. Forest Energy Resources, Inc. then merged with a
newly formed subsidiary of Mariner, became a new wholly owned
subsidiary of Mariner and changed its name to Mariner Energy
Resources, Inc. (MERI). Immediately following the
merger, approximately 59% of the Mariner common stock was held
by shareholders of Forest and approximately 41% of Mariner
common stock was held by the pre-merger stockholders of Mariner.
To acquire MERI, Mariner issued 50,637,010 shares of its
common stock to Forest shareholders. The aggregate consideration
was valued at $890.0 million, comprised of
$3.8 million in pre-merger costs and $886.2 million in
common stock, based on the closing price of the Companys
common stock of $17.50 per share on September 12, 2005
(which was the date that the terms of the acquisition were
announced).
The Forest Transaction was accounted for using the purchase
method of accounting under the accounting standards established
in Statement of Financial Accounting Standards No. 141,
Business Combinations (SFAS 141) and
No. 142, Goodwill and Other Intangible Assets. As a
result, the assets and liabilities acquired by Mariner in the
Forest Transaction are included in the Companys
June 30, 2006 balance sheet. The Company reflected the
results of operations of the Forest Transaction beginning
March 2, 2006. The Company recorded the estimated fair
values of the assets acquired and liabilities assumed at the
March 2, 2006 closing date, which are summarized in the
following table:
|
|
|
|
|
|
|
(In millions)
|
|
|
Oil and natural gas properties
|
|
$
|
1,211.4
|
|
Abandonment liabilities
|
|
|
(165.2
|
)
|
Long-term debt
|
|
|
(176.2
|
)
|
Fair value of oil and natural gas
derivatives
|
|
|
(17.5
|
)
|
Deferred tax liability
|
|
|
(199.4
|
)
|
Other assets and liabilities
|
|
|
(24.5
|
)
|
Goodwill
|
|
|
261.4
|
|
|
|
|
|
|
Net Assets Acquired
|
|
$
|
890.0
|
|
|
|
|
|
|
The Forest Transaction includes a large undeveloped offshore
acreage position which complements the Companys large
seismic database and a large portfolio of potential exploratory
prospects. The initial fair value estimate of the underlying
assets and liabilities acquired is determined by estimating the
value of the underlying proved reserves at the transaction date
plus or minus the fair value of other assets and liabilities,
including inventory, unproved oil and gas properties, gas
imbalances, debt (at face value), derivatives, and abandonment
liabilities. The deferred tax liability recognizes the
difference between the historical tax basis of the assets of
Forest Energy Resources, Inc. and the acquisition cost recorded
for book purposes. The purchase price allocation is preliminary
and will be subject to change as additional information becomes
available. The final purchase price allocation may differ in
material respects from that presented above. Carryover basis
accounting applies for tax purposes.
Goodwill represents the excess of the purchase price over the
estimated fair value of the assets acquired net of the fair
value of liabilities assumed in the acquisition. SFAS 142,
Goodwill and Other Intangible Assets, requires that
intangible assets with indefinite lives, including goodwill, be
evaluated on an annual basis at
F-7
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
December 31 for impairment or more frequently if an event
occurs or circumstances change that could potentially result in
an impairment.
The sources and uses of funds related to the Forest Transaction
were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Sources
|
|
|
Uses
|
|
|
Mariner Energy, Inc. and Mariner
Energy Resources, Inc. bank loan proceeds
|
|
$
|
180.2
|
|
|
$
|
|
|
Refinancing of assumed debt
|
|
|
|
|
|
|
176.2
|
|
Acquisition costs and other
expenses
|
|
|
|
|
|
|
4.0
|
|
In addition, approximately $3.8 million in merger-related
costs were funded from bank loan proceeds prior to the closing
of the transaction.
On March 2, 2006, Mariner and Mariner Energy Resources,
Inc. entered into a $500 million senior secured revolving
credit facility and an additional $40 million senior
secured letter of credit facility. Please refer to Note 4,
Long Term Debt for further discussion of the amended
and restated bank credit facility.
Payable to Forest In the merger
documentation, Forest and Mariner agreed that, beginning on
July 1, 2005, operating expenses of the Forest Gulf of
Mexico operations would be for the account of Mariner. In
addition, Forest and MERI entered into a transition services
agreement under which Forest provides services to MERI on an
as-needed basis for a limited period of time after the Forest
Transaction until the services can be transitioned to Mariner.
As a result of these arrangements, MERI has incurred working
capital charges that are payable to Forest. Through
June 30, 2006, net charges incurred were
$38.4 million, of which $24.8 million remained
outstanding as a component of accrued liabilities at
June 30, 2006. A total of $20.8 million was incurred
prior to the Forest Transaction and the remaining amounts were
incurred after the Forest Transaction. The $24.8 million
accrued liability outstanding at June 30, 2006 was paid by
MERI in July 2006 in satisfaction of these obligations.
Pro Forma Financial Information The pro forma
information set forth below gives effect to our merger with
Forest Energy Resources, Inc. as if it had been consummated as
of the beginning of the applicable period. The merger was
consummated on March 2, 2006. The pro forma information has
been derived from the historical consolidated financial
statements of the Company and the statements of revenues and
direct operating expenses of the Forest Gulf of Mexico
operations. The pro forma information is for illustrative
purposes only. The financial results may have been different had
the Forest Gulf of Mexico operations been an independent company
and had the companies always been combined. You should not rely
on the pro forma financial information as being indicative of
the historical results that would have been achieved had the
merger occurred in the past or the future financial results that
the Company will achieve after the merger.
|
|
|
|
|
|
|
|
|
|
|
Six-Months Ended June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Pro Forma:
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
315,407
|
|
|
$
|
341,915
|
|
Net income available to common
stockholders
|
|
$
|
56,233
|
|
|
$
|
56,308
|
|
Basic earnings per share
|
|
$
|
0.67
|
|
|
$
|
0.68
|
|
Diluted earnings per share
|
|
$
|
0.66
|
|
|
$
|
0.68
|
|
Secured Bank Credit Facility On March 2,
2004, the Company obtained a revolving line of credit with
initial advances of $135 million from a group of banks led
by Union Bank of California, N.A. and BNP
F-8
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Paribas. The bank credit facility initially provided up to
$150 million of revolving borrowing capacity, subject to a
borrowing base, and a $25 million term loan. The initial
advance was made in two tranches: a $110 million
Tranche A and a $25 million Tranche B. The
Tranche B loan was converted to a Tranche A note in
July 2004 and all subsequent advances under the credit facility
were Tranche A advances.
The borrowing base is based upon the evaluation by the lenders
of the Companys oil and gas reserves and other factors.
Any increase in the borrowing base requires the consent of all
lenders. Substantially all of the Companys assets are
pledged to secure the bank credit facility.
Amendments of Secured Bank Credit
Facility In connection with the Forest
Transaction, on March 2, 2006 the Company amended and
restated the existing bank credit facility to, among other
things, increase maximum credit availability to
$500 million, with a $400 million borrowing base as of
that date, add an additional dedicated $40 million letter
of credit facility, and add Mariner Energy Resources, Inc. as a
co-borrower.
The revolving credit facility will mature on March 2, 2010,
and the $40 million letter of credit facility will mature
on March 2, 2009. Mariner used borrowings under the
revolving credit facility to facilitate the merger and to retire
existing debt, and it may use borrowings in the future for
general corporate purposes. The $40 million letter of
credit facility has been used to obtain a letter of credit in
favor of Forest to secure Mariners performance of its
obligation to drill 150 wells under an existing
drill-to-earn
program and is not included as a use of the borrowing base. The
outstanding principal balance of loans under the revolving
credit facility may not exceed the borrowing base, which
initially was set at $400 million. If the borrowing base
falls below the outstanding balance under the revolving credit
facility, Mariner will be required to prepay the deficit, pledge
additional unencumbered collateral, repay the deficit and cash
collateralize certain letters of credit, or effect some
combination of such prepayment, pledge and repayment and
collateralization.
On April 7, 2006, the borrowing base under the
Companys amended and restated bank credit facility was
increased to $430 million, subject to redetermination or
adjustment. On April 24, 2006, the borrowing base was
reduced to $362.5 million in accordance with an amendment
to the revolving credit facility related to the Companys
offering of $300 million of senior notes. For subsequent
qualifying bond issuances, the amendment provides that the
borrowing base in effect on the closing date of such a bond
issuance will automatically reduce by 25% of the aggregate
principal amount of such bond issuance to the extent that it
does not refinance the principal amount of an existing bond
issuance. The bank credit facility permits Mariners
issuance of certain unsecured bonds of up to $350 million
in aggregate principal amount that have a non-default interest
rate of 10% or less per annum and a scheduled maturity date
after March 1, 2012. Mariners sale and issuance of
$300 million of senior notes in April 2006 constituted such
a qualifying bond issuance. At June 30, 2006, we had
approximately $161.2 million in advances outstanding under
our revolving credit facility, including a $4.2 million
letter of credit required for plugging and abandonment
obligations at one of our offshore fields. We anticipate that
the borrowing base will be increased to $450 million in
October 2006, subject to redetermination or adjustment.
The amended and restated bank credit facility contains various
restrictive covenants and other usual and customary terms and
conditions of a revolving bank credit facility, including
limitations on the payment of cash dividends and other
restricted payments, the incurrence of additional debt, the sale
of assets, and speculative hedging. The financial covenants were
modified under the amended and restated bank credit facility to
require the Company to, among other things:
|
|
|
|
|
maintain a ratio of consolidated current assets plus the unused
borrowing base to consolidated current liabilities of not less
than 1.0 to 1.0; and
|
|
|
|
maintain a ratio of total debt to EBITDA of not more than 2.5 to
1.0.
|
The Company was in compliance with the financial covenants under
the bank credit facility as of June 30, 2006.
As of June 30, 2006 and December 31, 2005,
$157.0 million and $152.0 million, respectively, was
outstanding under the bank credit facility, and the weighted
average interest rate was 6.85% and 7.15%,
F-9
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
respectively. Net proceeds of approximately $38 million
generated by the Private Equity Placement in March 2005 were
used to repay existing bank debt.
The Company must pay a commitment fee of 0.25% to 0.50% per
year on the unused availability under the bank credit facility.
Private Offering of Senior Unsecured Notes due
2013 On April 24, 2006, the Company sold
and issued to eligible purchasers $300 million aggregate
principal amount of its
71/2% senior
notes due 2013 (the Notes) pursuant to
Rule 144A under the Securities Act of 1933, as amended. The
Notes were priced to yield 7.75% to maturity. Net proceeds,
after deducting initial purchasers discounts and
commissions and offering expenses, were approximately
$287.9 million. Mariner used the net proceeds of the
offering to repay debt under the bank credit facility. The
issuance of the Notes was a qualifying bond issuance under
Mariners secured bank credit facility and resulted in an
automatic reduction of its borrowing base to $362.5 million
as of April 24, 2006.
The Notes are senior unsecured obligations of the Company, rank
senior in right of payment to any future subordinated
indebtedness, rank equally in right of payment with the
Companys existing and future senior unsecured indebtedness
and are effectively subordinated in right of payment to the
Companys senior secured indebtedness, including its
obligations under its credit facility, to the extent of the
collateral securing such indebtedness, and to all existing and
future indebtedness and other liabilities of any non-guarantor
subsidiaries.
The Notes are jointly and severally guaranteed on a senior
unsecured basis by the Companys existing and future
domestic subsidiaries. In the future, the guarantees may be
released or terminated under certain circumstances. Each
subsidiary guarantee ranks senior in right of payment to any
future subordinated indebtedness of the guarantor subsidiary,
ranks equally in right of payment to all existing and future
senior unsecured indebtedness of the guarantor subsidiary and
effectively subordinate to all existing and future secured
indebtedness of the guarantor subsidiary, including its
guarantees of indebtedness under the Companys credit
facility, to the extent of the collateral securing such
indebtedness.
The Company will pay interest on the Notes on April 15 and
October 15 of each year, beginning on October 15, 2006. The
Notes mature on April 15, 2013. There is no sinking fund
for the Notes.
The Company may redeem the Notes at any time prior to
April 15, 2010 at a price equal to the principal amount
redeemed plus a make-whole premium, using a discount rate of the
Treasury rate plus 0.50% and accrued but unpaid interest.
Beginning on April 15 of the years indicated below, the Company
may redeem the Notes from time to time, in whole or in part, at
the prices set forth below (expressed as percentages of the
principal amount redeemed) plus accrued but unpaid interest:
2010 at 103.750%
2011 at 101.875%
2012 and thereafter at 100.000%
In addition, prior to April 15, 2009, the Company may
redeem up to 35% of the Notes with the proceeds of equity
offerings at a price equal to 107.50% of the principal amount of
the Notes redeemed. If the Company experiences a change of
control (as defined in the indenture governing the Notes),
subject to certain exceptions, the Company must give holders of
the Notes the opportunity to sell to the Company their Notes, in
whole or in part, at a purchase price equal to 101% of the
principal amount, plus accrued and unpaid interest and
liquidated damages to the date of purchase.
The Company and its restricted subsidiaries are subject to
certain negative covenants under the indenture governing the
Notes. The indenture governing the Notes limits the
Companys and each of its restricted subsidiaries
ability to, among other things:
F-10
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
incur additional indebtedness or issue preferred stock;
|
|
|
|
create certain liens;
|
|
|
|
sell assets;
|
|
|
|
enter into agreements that restrict dividends or other payments
from its subsidiaries to itself;
|
|
|
|
consolidate, merge or transfer all or substantially all of its
assets;
|
|
|
|
engage in transactions with affiliates;
|
|
|
|
pay dividends or make other distributions on capital stock or
subordinated indebtedness; and
|
|
|
|
create unrestricted subsidiaries.
|
Under an Exchange and Registration Rights Agreement executed on
April 24, 2006 relating to the Notes, the Company agreed to:
|
|
|
|
|
file a registration statement within 180 days after the
closing date of the offering enabling holders of Notes to
exchange the privately placed Notes offered in this offering for
publicly registered Notes with substantially identical terms;
|
|
|
|
use its reasonable best efforts to cause the registration
statement to become effective within 270 days after the
closing date of the offering and to complete the exchange offer
within 360 days after the closing of the offering; and
|
|
|
|
file a shelf registration statement for the resale of the Notes
if it cannot effect an exchange offer within the time periods
listed above and in other circumstances.
|
If the Company fails to comply with its obligations to register
the Notes within the specified time periods, it will be required
to pay special interest on the Notes.
Costs associated with the Notes offering were approximately
$8.3 million, excluding discounts of $3.8 million.
JEDI Term Promissory Note On March 2,
2004, the Company issued a $10 million term promissory note
to JEDI as a part of merger consideration. The note matured on
March 2, 2006, and bore interest, payable in kind at our
option, at a rate of 10% per annum until March 2,
2005, and 12% per annum thereafter unless paid in cash in
which event the rate remained 10% per annum. We chose to
pay interest in cash rather than in kind. The JEDI note was
secured by a lien on three of the Companys non-proven,
non-producing properties located in the Outer Continental Shelf
of the Gulf of Mexico. The Company could offset against the note
the amount of certain claims for indemnification that could be
asserted against JEDI under the terms of the merger agreement.
The JEDI term promissory note contained customary events of
default, including the occurrence of an event of default under
the Companys bank credit facility. In March 2005, the
Company repaid $6.0 million of the note utilizing proceeds
from the Private Equity Placement in March 2005. The
$4.0 million balance remaining on the JEDI note was repaid
in full on its maturity date of March 2, 2006.
Cash Interest Expense For the six-month
periods ended June 30, 2006 and 2005, interest payments
were $8.4 million and $2.8 million, respectively.
Bank Debt Issuance Costs The Company
capitalizes certain direct costs associated with the issuance of
long term debt. In conjunction with the Forest Transaction, the
Companys bank credit facility was amended and restated to,
among other things, increase the borrowing capacity from
$185 million to $400 million, based upon an initial
borrowing base of that amount. The amendment and restatement was
treated as an extinguishment of debt for accounting purposes.
This treatment resulted in a charge of approximately
F-11
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$1.2 million in the first quarter of 2006. This charge is
included in the interest expense line of the consolidated
statement of operations.
|
|
5.
|
Oil and
Gas Properties
|
Oil and gas properties are accounted for using the full-cost
method of accounting. All direct costs and certain indirect
costs associated with the acquisition, exploration and
development of oil and gas properties are capitalized.
Amortization of oil and gas properties is provided using the
unit-of-production
method based on estimated proved oil and gas reserves. No gains
or losses are recognized upon the sale or disposition of oil and
gas properties unless the sale or disposition represents a
significant quantity of oil and gas reserves, which would have a
significant impact on the depreciation, depletion and
amortization rate.
Under full cost accounting rules, total capitalized costs are
limited to a ceiling equal to the present value of future net
revenues, discounted at 10% per annum, plus the lower of cost or
fair value of unproved properties less income tax effects (the
ceiling limitation). We perform a quarterly ceiling
test to evaluate whether the net book value of our full cost
pool exceeds the ceiling limitation. If capitalized costs (net
of accumulated depreciation, depletion and amortization) less
related deferred taxes are greater than the discounted future
net revenues or ceiling limitation, a write-down or impairment
of the full cost pool is required. A write-down of the carrying
value of the full cost pool is a non-cash charge that reduces
earnings and impacts stockholders equity in the period of
occurrence and typically results in lower depreciation,
depletion and amortization expense in future periods. Once
incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices
in effect as of the balance sheet date and adjusted for
basis or location differential, held constant over
the life of the reserves. We use derivative financial
instruments that qualify for cash flow hedge accounting under
SFAS 133, Accounting for Derivative Instruments and
Hedging Activities to hedge against the volatility of
natural gas prices and, in accordance with SEC guidelines, we
include estimated future cash flows from our hedging program in
our ceiling test calculation. In addition, subsequent to the
adoption of SFAS 143, Accounting for Asset Retirement
Obligations, the future cash outflows associated with
settling asset retirement obligations are not included in the
computation of the discounted present value of future net
revenues for the purposes of the ceiling test calculation.
|
|
6.
|
Accrual
for Future Abandonment Costs
|
SFAS No. 143, Accounting for Asset Retirement
Obligations, addresses accounting and reporting for
obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. The
Company adopted SFAS No. 143 on January 1, 2003.
SFAS No. 143 requires that the fair value of a
liability for an assets retirement obligation be recorded
in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present
value each period, and the capitalized cost is depreciated over
the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or
loss is recognized.
The following roll-forward is provided as a reconciliation of
the beginning and ending aggregate carrying amounts of the asset
retirement obligation.
F-12
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
(In millions)
|
|
|
Abandonment liability as of
December 31, 2005(1)
|
|
$
|
49.5
|
|
Liabilities Incurred
|
|
|
17.3
|
|
Claims Settled
|
|
|
(12.1
|
)
|
Accretion Expense
|
|
|
6.6
|
|
Revisions to previous estimates
|
|
|
5.3
|
|
Liabilities incurred from assets
acquired(2)
|
|
|
165.2
|
|
|
|
|
|
|
Abandonment Liability as of
June 30, 2006(3)
|
|
$
|
231.8
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $11.4 million classified as a current accrued
liability at December 31, 2005. |
|
(2) |
|
Represents the fair value of the asset retirement obligation
acquired through the Forest Transaction. |
|
(3) |
|
Includes $43.1 million classified as a current accrued
liability at June 30, 2006. |
Increase in Number of Shares Outstanding
On March 2, 2006, the Companys certificate of
incorporation was amended to increase its authorized stock to
200,000,000 shares, of which 180,000,000 shares are
common stock and 20,000,000 shares are preferred stock.
Equity Participation Plan We adopted an
Equity Participation Plan, as amended, that provided for the
one-time grant at the closing of our Private Equity Placement on
March 11, 2005 of 2,267,270 restricted shares of our common
stock to certain of our employees. No further grants will be
made under the Equity Participation Plan, although persons who
received such a grant are eligible for future awards of
restricted stock or stock options under our Amended and Restated
Stock Incentive Plan, as amended, described below. We intended
the grants of restricted stock under the Equity Participation
Plan to serve as a means of incentive compensation for
performance and not primarily as an opportunity to participate
in the equity appreciation of our common stock. Therefore,
Equity Participation Plan grantees did not pay any consideration
for the common stock they received, and we received no
remuneration for the stock. As a result of closing the Forest
Transaction, all shares of restricted stock granted under the
Equity Participation Plan vested as follows: (i) the
463,656 shares of restricted stock held by non-executive
employees vested on March 2, 2006, and (ii) the
1,803,614 shares of restricted stock held by executive
officers vested on May 31, 2006 pursuant to an agreement,
made in exchange for a cash payment of $1,000 to each officer,
that his or her shares of restricted stock would not vest before
the later of March 11, 2006 or ninety days after the
effective date of the merger. The Equity Participation Plan
expired upon the vesting of all shares granted thereunder. Stock
could be withheld by us upon vesting to satisfy our tax
withholding obligations with respect to the vesting of the
restricted stock. Participants in the Equity Participation Plan
had the right to elect to have us withhold and cancel shares of
the restricted stock to satisfy our tax withholding obligations.
In such events, we would be required to pay any tax withholding
obligation in cash. As a result of such participant elections,
we withheld an aggregate 807,376 shares that otherwise
would have remained outstanding upon vesting of the restricted
stock, reducing the aggregate outstanding vested stock grants
made under the Equity Participation Plan to
1,459,894 shares. The 807,376 shares withheld became
treasury shares that were retired and restored to the status of
authorized and unissued shares of common stock. We paid in cash
the associated withholding taxes of $14.7 million.
Amended and Restated Stock Incentive Plan We
adopted a Stock Incentive Plan which became effective
March 11, 2005 and was amended and restated on
March 2, 2006 and further amended on March 16, 2006.
Awards to participants under the Amended and Restated Stock
Incentive Plan may be made in the form of incentive stock
options, or ISOs, non-qualified stock options or restricted
stock. The participants to whom
F-13
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
awards are granted, the type or types of awards granted to a
participant, the number of shares covered by each award, the
purchase price, conditions and other terms of each award are
determined by the Board of Directors or a committee thereof. A
total of 6,500,000 shares of Mariners common stock is
subject to the Amended and Restated Stock Incentive Plan. No
more than 2,850,000 shares issuable upon exercise of
options or as restricted stock can be issued to any individual.
Unless sooner terminated, no award may be granted under the
Amended and Restated Stock Incentive Plan after October 12,
2015.
During the six months ended June 30, 2006, we granted
762,483 shares of restricted stock under the Amended and
Restated Stock Incentive Plan. As of June 30, 2006,
750,145 shares of restricted common stock and options
exercisable for 751,800 shares of common stock remained
outstanding under the Amended and Restated Stock Incentive Plan,
and 4,949,855 shares remained available thereunder for
future issuance to participants.
During the six months ended June 30, 2005, we granted
options to purchase 788,560 shares of common stock under
the Stock Incentive Plan. In 2005, additional options to
purchase 20,440 shares of common stock were granted under
the Stock Incentive Plan.
Rollover Options. In connection with the
Forest Transaction, the Company, during the six months ended
June 30, 2006, granted options to acquire
156,626 shares of the Companys common stock to
certain former employees of Forest or Forest Energy Resources,
Inc. (Rollover Options). The Rollover Options are
evidenced by non-qualified stock option agreements and are not
covered by the Amended and Restated Stock Incentive Plan. As of
June 30, 2006, Rollover Options to purchase
114,208 shares of the Companys common stock remained
outstanding.
The Company adopted
SFAS No. 123-Revised
2004 (SFAS No. 123(R)), Share-Based
Payment, using the modified retrospective application
effective January 1, 2005. As a result of the adoption of
SFAS No. 123(R), we recorded compensation expense for
the value of restricted stock that was granted pursuant to our
Equity Participation Plan. We also record compensation expense
for the value of restricted stock and options granted under the
Stock Incentive Plan before March 2, 2006 and the Amended
and Restated Stock Incentive Plan, as amended, on and after
March 2, 2006. The fair value of the restricted shares at
date of grant is being recorded in stockholders equity as
a component of additional paid in capital and is being amortized
over the vesting period as compensation expense. We recorded
compensation expense of $7.9 million and $9.5 million
for the six-month periods ended June 30, 2006 and 2005,
respectively, related to the restricted stock granted in 2005
and 2006 and stock options outstanding for the periods then
ended. As of June 30, 2006, the participants were fully
vested in the restricted stock granted under the Equity
Participation Plan and no unrecognized compensation remains.
Under the Amended and Restated Stock Incentive Plan,
unrecognized compensation related to the unvested portion of the
restricted stock granted was $14.0 million at June 30,
2006. Unrecognized compensation expense for non-vested options
was $0.7 million at June 30, 2006.
A summary of stock option activity as of June 30, 2006 and
2005, respectively, and changes during the six-month period is
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Exercise
|
|
|
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Outstanding at beginning of
period: January 1,
|
|
|
809,000
|
|
|
$
|
14.02
|
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
156,626
|
(1)
|
|
|
8.31
|
|
|
|
788,560
|
(3)
|
|
|
14.00
|
|
Exercised
|
|
|
(48,200
|
)
|
|
|
14.00
|
|
|
|
|
|
|
|
|
|
Expired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(51,418
|
)(1)(2)
|
|
|
11.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-14
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Exercise
|
|
|
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Outstanding at end of period:
June 30,
|
|
|
866,008
|
|
|
$
|
13.77
|
|
|
|
788,560
|
|
|
|
14.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding exercisable at end of
period: June 30,
|
|
|
362,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for future grant as
options or restricted stock
|
|
|
4,949,855
|
|
|
|
|
|
|
|
1,211,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The options exercisable for an aggregate 156,626 shares
were the Rollover Options granted pursuant to the Forest
Transaction merger agreement. Rollover Options exercisable for
an aggregate 42,418 shares were forfeited due to
terminations of employment with Mariner Energy Resources, Inc.,
but are not indicative of a historical forfeiture rate. |
|
(2) |
|
In-the-money
options exercisable for an aggregate 9,000 shares issued to
two directors of the Company were cancelled on March 31,
2006 and replaced by restricted stock grants. |
|
(3) |
|
The option grants were made under Mariners Stock Incentive
Plan. |
The following table summarizes certain information about stock
options outstanding at June 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Number
|
|
|
Exercise
|
|
Range of Exercise Prices
|
|
Outstanding
|
|
|
Life (Years)
|
|
|
Price
|
|
|
Exercisable
|
|
|
Price
|
|
|
$8.81 $17.00
|
|
|
866,008
|
|
|
|
8.0
|
|
|
$
|
13.77
|
|
|
|
362,470
|
|
|
$
|
14.00
|
|
The following table summarizes certain information about stock
options outstanding at June 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Number
|
|
|
Exercise
|
|
Range of Exercise Prices
|
|
Outstanding
|
|
|
Life (Years)
|
|
|
Price
|
|
|
Exercisable
|
|
|
Price
|
|
|
$14.00
|
|
|
788,560
|
|
|
|
9.7
|
|
|
$
|
14.00
|
|
|
|
|
|
|
|
|
|
Options generally vest over two to three-year periods and are
exercisable for periods ranging from seven to ten years. The
weighted average fair value of options granted during the six
months ended June 30, 2006 and 2005 was $2.36 and $2.72,
respectively. The fair value of each option award is estimated
on the date of grant using the Black-Scholes option valuation
model that uses the assumptions noted in the following table:
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended
|
|
|
|
June 30, 2006:
|
|
|
|
Amended and
|
|
|
|
|
|
|
Restated Stock
|
|
|
|
|
|
|
Incentive Plan
|
|
|
Rollover
|
|
|
|
Options
|
|
|
Options
|
|
|
Expected Life (years)
|
|
|
5.0
|
|
|
|
4.3
|
|
Risk Free Interest Rate
|
|
|
4.89
|
%
|
|
|
4.93
|
%
|
Expected Volatility
|
|
|
35
|
%
|
|
|
35
|
%
|
Dividend Yield
|
|
|
0.0
|
%
|
|
|
0.0
|
%
|
F-15
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Black-Scholes option valuation model assumptions were for
the six-month period ended June 30, 2005:
|
|
|
|
|
|
|
Stock
|
|
|
|
Incentive
|
|
|
|
Plan
|
|
|
Expected Life (years)
|
|
|
3.0
|
|
Risk Free Interest Rate
|
|
|
3.8
|
%
|
Expected Volatility
|
|
|
38
|
%
|
Dividend Yield
|
|
|
0.0
|
%
|
The expected life (estimated period of time outstanding) of
options granted was estimated. The expected volatility was based
on historical volatility for a period equal to the stock
options expected life. The risk free rate is based on the
U.S. Treasury yield curve in effect at the time of grant.
The dividend yield is based on the Companys ability to pay
dividends.
A summary of the activity for nonvested restricted stock share
awards under the Amended and Restated Stock Incentive Plan as of
June 30, 2006 and 2005, respectively, and changes during
the six-month period is as follows:
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares Under the Amended and Restated Stock
Incentive Plan
|
|
|
|
June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
Total nonvested shares at
beginning of period: January 1
|
|
|
|
|
|
|
|
|
Shares granted
|
|
|
762,483
|
|
|
|
|
|
Share vested
|
|
|
|
|
|
|
|
|
Shares forfeited
|
|
|
(12,338
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total nonvested shares at end of
period: June 30
|
|
|
750,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total vested shares at end of
period: June 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for future grant as
options or restricted stock
|
|
|
4,949,855
|
|
|
|
|
|
Average Fair Value of
Shares Granted During the Period
|
|
$
|
19.53
|
|
|
$
|
|
|
A summary of the activity for nonvested restricted stock share
awards under the Equity Participation Plan as of June 30,
2006 and 2005, respectively, and changes during the six-month
period is as follows:
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares Under the
|
|
|
|
Equity Participation Plan
|
|
|
|
June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
Total nonvested shares at
beginning of period: January 1
|
|
|
2,267,270
|
|
|
|
|
|
Shares granted
|
|
|
|
|
|
|
2,267,270
|
|
Share vested
|
|
|
(2,267,270
|
)
|
|
|
|
|
Shares forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total nonvested shares at end of
period: June 30
|
|
|
0
|
|
|
|
2,267,270
|
|
|
|
|
|
|
|
|
|
|
Total vested shares at end of
period: June 30
|
|
|
2,267,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for future grant under
Equity Participation Plan
|
|
|
|
|
|
|
|
|
Average Fair Value of
Shares Granted During the Period
|
|
|
|
|
|
$
|
14.00
|
|
F-16
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Private Equity Placement. In March 2005, the
Company sold and issued 16,350,000 shares of its common
stock in the Private Equity Placement for net proceeds of
$212.9 million, before offering expenses of
$2.2 million, of which $166.0 million were used to
redeem 12,750,000 shares of the Companys common stock
from its sole stockholder.
|
|
8.
|
Commitments
And Contingencies
|
Minimum Future Lease Payments The Company
leases certain office facilities and other equipment under
long-term operating lease arrangements. Minimum rental
obligations under the Companys operating leases in effect
at June 30, 2006 are as follows (in millions):
|
|
|
|
|
2007
|
|
$
|
1.4
|
|
2008
|
|
|
1.3
|
|
2009
|
|
|
1.0
|
|
2010
|
|
|
1.3
|
|
2011 and thereafter
|
|
|
2.3
|
|
Hedging Program The energy markets have
historically been very volatile, and we expect that oil and gas
prices will be subject to wide fluctuations in the future. In an
effort to reduce the effects of the volatility of the price of
oil and natural gas on the Companys operations, management
has elected to hedge oil and natural gas prices from time to
time through the use of commodity price swap agreements and
costless collars. While the use of these hedging arrangements
limits the downside risk of adverse price movements, it also
limits future gains from favorable movements. In addition,
forward price curves and estimates of future volatility are used
to assess and measure the ineffectiveness of our open contracts
at the end of each period. If open contracts cease to qualify
for hedge accounting, the mark to market change in fair value is
recognized in the income statement. Loss of hedge accounting and
cash flow designation will cause volatility in earnings. The
fair values we report in our financial statements change as
estimates are revised to reflect actual results, changes in
market conditions or other factors, many of which are beyond our
control.
The cash losses on contracts settled for natural gas and oil
produced during the six-month period ended June 30, 2006
was $11.8 million. A $3.9 million non-cash gain was
also recorded for the six-month period ended June 30, 2006
relating to the hedges acquired through the Forest transaction.
Additionally, an unrealized loss of $1.0 million was
recognized for the six-month period ended June 30, 2006
related to the ineffective portion of open contracts that were
not eligible for deferral under SFAS 133 due primarily to
the basis differentials between the contract price, which is
NYMEX-based for oil and Henry Hub-based for gas, and the indexed
price at the point of sale.
As of June 30, 2006, the Company had the following fixed
price swaps outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2006 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
862,960
|
|
|
$
|
72.41
|
|
|
$
|
(2.6
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
9,752,000
|
|
|
|
6.92
|
|
|
|
(0.2
|
)
|
January 1
March 31, 2007
|
|
|
3,690,010
|
|
|
|
9.30
|
|
|
|
(4.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(6.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-17
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of June 30, 2006, the Company had the following costless
collars outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 Fair Value
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
126,960
|
|
|
$
|
32.65
|
|
|
$
|
41.52
|
|
|
$
|
(4.2
|
)
|
January 1
December 31, 2007
|
|
|
1,533,775
|
|
|
|
59.13
|
|
|
|
82.85
|
|
|
|
(7.3
|
)
|
January 1
December 31, 2008
|
|
|
1,080,020
|
|
|
|
61.63
|
|
|
|
86.80
|
|
|
|
(0.2
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1
December 31, 2006
|
|
|
3,703,920
|
|
|
|
5.78
|
|
|
|
7.85
|
|
|
|
(1.8
|
)
|
January 1
December 31, 2007
|
|
|
14,106,750
|
|
|
|
6.87
|
|
|
|
11.82
|
|
|
|
(9.0
|
)
|
January 1
December 31, 2008
|
|
|
12,347,000
|
|
|
|
7.83
|
|
|
|
14.60
|
|
|
|
3.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(18.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to June 30, 2006, Mariner entered into the
following hedging transactions:
|
|
|
|
|
|
|
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
October 1
December 31, 2006
|
|
|
260,360
|
|
|
$
|
72.35
|
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
October 1
December 31, 2006
|
|
|
5,451,000
|
|
|
$
|
9.16
|
|
January 1, 2007
December 31, 2007
|
|
|
12,156,323
|
|
|
$
|
9.79
|
|
January 1, 2008
September 30, 2008
|
|
|
3,059,689
|
|
|
$
|
9.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2007
|
|
|
498,914
|
|
|
$
|
62.00
|
|
|
$
|
88.40
|
|
January 1
December 31, 2008
|
|
|
115,475
|
|
|
|
62.00
|
|
|
|
86.85
|
|
The Company has reviewed the financial strength of its
counterparties and believes the credit risk associated with
these swaps and costless collars to be minimal.
Other Commitments In the ordinary course of
business, the Company enters into long-term commitments to
purchase seismic data. The minimum annual payments under these
contracts are $22.9 million, $19.5 million and
$4.0 million in 2006, 2007 and 2008, respectively. In 2005,
the Company entered into a joint exploration agreement granting
the joint venture partner the right to participate in prospects
covered by certain seismic data licensed by the Company in
return for $6.0 million in scheduled payments to be
received by the Company over a two-year period.
MMS Appeal Mariner and a subsidiary own
numerous properties in the Gulf of Mexico. Certain of such
properties were leased from the Minerals Management Service
(MMS) subject to the 1996 Royalty Relief Act. This
Act relieved the obligation to pay royalties on certain leases
until a designated volume is produced. Two of these leases held
by the Company and one held by MERI contained language that
limited royalty relief if commodity prices exceeded
predetermined levels. Since 2000, commodity prices have exceeded
the predetermined levels, except in 2002. The Company and its
subsidiary believe the MMS did not have the authority to set
pricing limits in these leases and have withheld payment of
royalties on the leases while disputing the MMS authority
in two pending proceedings. The Company has recorded a liability
for 100% of the exposure on its two leases, which at
June 30, 2006 was $18.8 million. In April 2005, the
MMS
F-18
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
denied Mariners administrative appeal of the MMS
April 2001 order asserting royalties were due because price
limits had been exceeded. In October 2005, Mariner filed suit in
the U.S. District Court for the Southern District of Texas
seeking judicial review of the dismissal. Upon motion of the
MMS, the Companys lawsuit was dismissed on procedural
grounds. In August 2006, the Company filed an appeal of such
dismissal. The Company had also filed an administrative appeal
of a December 2005 order of the MMS demanding royalties for
calendar year 2004 under the same leases at issue in the April
2001 MMS order. However, the MMS withdrew such order,
rendering the appeal moot. Thereafter, in May 2006, the MMS
issued an order asserting price limits were exceeded in calendar
years 2001, 2003 and 2004 and, accordingly, that royalties were
due under such leases on oil and gas produced in those years.
Mariner has filed and is pursuing an administrative appeal of
that order.
The potential liability of MERI under its lease subject to the
1996 Royalty Relief Act containing such commodity price
threshold language is approximately $1.8 million as of
June 30, 2006. This potential liability relates to
production from the lease commencing July 1, 2005, the
effective date of Mariners acquisition of MERI. A reserve
for this possible liability will be made when deemed
appropriate. The MMS has not yet made demand for non-payment of
royalties alleged to be due for calendar years subsequent to
2004 on the basis of price thresholds being exceeded.
Insurance Matters In September 2004, the
Company incurred damage from Hurricane Ivan that affected its
Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields.
Production from Mississippi Canyon 357 was shut-in until March
2005, when necessary repairs were completed and production
recommenced. It subsequently has been shut-in since Hurricane
Katrina, with production expected to recommence in the fourth
quarter of 2006 after completion of host platform repairs.
Production from Ochre recommenced in September 2006 after
completion of repairs to a host platform, with production at
about the same net rate of approximately 6.5 MMcfe per day
as it was immediately prior to Hurricane Ivan. We expect to be
reimbursed for costs expended in excess of our annual deductible
of $1.25 million plus the single occurrence deductible of
$.375 million for the insurance period ended
September 30, 2004. We recovered approximately
$2.0 million in insurance proceeds in the second quarter of
2006.
In 2005, our operations were adversely affected by one of the
most active and severe hurricane seasons in recorded history,
resulting in shut-in production and startup delays. We estimate
that as of September 30, 2006, approximately 12 MMcfe
per day of production remained shut-in and approximately
33 MMcfe per day of production had recommenced since
June 30, 2006. The four deepwater projects that experienced
startup delays have recommenced production. As a result of
ongoing repairs to pipelines, facilities, terminals and host
facilities, we expect most of the remaining shut-in production
to recommence by the end of 2006 and the balance in 2007, except
that an immaterial amount of production is not expected to
recommence. Actual commencement or recommencement of deferred or
shut-in production will vary based on circumstances beyond our
control, including the timing of repairs to both onshore and
offshore platforms, pipelines and facilities, the actions of
operators on our fields, availability of service equipment, and
weather.
We estimate that the costs to repair damage caused by Hurricanes
Katrina and Rita to our platforms and facilities will be
approximately $80 million. However, until we are able to
complete all of the repair work, this estimate is subject to
significant variance. For the insurance period covering the 2005
hurricane activity, we carried a $3 million annual
deductible and a $0.5 million single occurrence deductible
for the Mariner assets. Insurance covering the Forest Gulf of
Mexico properties carried a $5 million deductible for each
occurrence. Until the repairs are completed and we submit costs
to our insurance underwriters for their review, the full extent
of our insurance recoveries and the resulting net costs to us
for Hurricanes Katrina and Rita will be unknown. However, we
expect the total costs not covered by the combined insurance
policies to be less than $15 million.
Effective March 2, 2006, Mariner has been accepted as a
member of OIL Insurance, Ltd., or OIL, an industry insurance
cooperative, through which the assets of both Mariner and the
Forest Gulf of Mexico
F-19
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
operations are insured. The coverage contains a $5 million
annual per occurrence deductible for the combined assets and a
$250 million per occurrence loss limit. However, if a
single event causes losses to OIL insured assets in excess of
$500 million, amounts covered for such losses will be
reduced on a pro rata basis among OIL members. We maintained our
commercially underwritten insurance coverage for the pre-merger
Mariner assets which expired on September 30, 2006. This
coverage contained a $3 million annual deductible and a
$500,000 occurrence deductible, $150 million of aggregate
loss limits, and limited business interruption coverage. While
the coverage was in effect, it was primary to the OIL coverage
for the pre-Forest Transaction Mariner assets. We have acquired
additional windstorm/physical damage insurance covering all of
Mariners assets to supplement the existing OIL coverage.
The coverage provides up to $31 million of annual loss
coverage (with no additional deductible) if recoveries from OIL
for insured losses are reduced by the OIL overall loss limit
(i.e., if losses to OIL insured assets from a single event
exceed $500 million). We have also acquired additional
limited business interruption insurance on most of our deep
water producing fields which becomes effective 60 days
after a field is shut-in due to a covered event. The coverage
varies by field and is limited to a maximum recovery resulting
from windstorm damage of approximately $43 million
(assuming all covered fields are shut-in for the full insurance
term of 365 days).
Litigation The Company, in the ordinary
course of business, is a claimant
and/or a
defendant in various legal proceedings, including proceedings as
to which the Company has insurance coverage and those that may
involve the filing of liens against the Company or its assets.
The Company does not consider its exposure in these proceedings,
individually or in the aggregate, to be material.
Letter of Credit On March 2, 2006,
Mariner obtained a $40 million letter of credit under its
senior secured credit facility. The letter of credit was issued
in favor of Forest to secure our performance of our obligations
under an existing
drill-to-earn
program. Based upon the number of wells drilled as of
September 30, 2006, we expect the first reduction in the
letter of credit to occur in accordance with its terms in
October 2006.
Basic earnings per share is calculated by dividing net income by
the weighted average number of shares of common stock
outstanding during the period. Fully diluted earnings per share
assumes the conversion of all potentially dilutive securities
and is calculated by dividing net income by the sum of the
weighted average number of shares of common stock outstanding
plus all potentially dilutive securities.
|
|
|
|
|
|
|
|
|
|
|
For the Six-Month Period Ended June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share data)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
41,834
|
|
|
$
|
28,620
|
|
Denominator:
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
67,244
|
|
|
|
31,976
|
|
Add dilutive securities
|
|
|
585
|
|
|
|
265
|
|
|
|
|
|
|
|
|
|
|
Total weighted average shares
outstanding and dilutive securities
|
|
|
67,829
|
|
|
|
32,241
|
|
|
|
|
|
|
|
|
|
|
Earnings per share
basic:
|
|
$
|
0.62
|
|
|
$
|
0.90
|
|
Earnings per share
diluted:
|
|
$
|
0.62
|
|
|
$
|
0.89
|
|
Please refer to Note 7 Stockholders
Equity for option and share activity for the six months
ended June 30, 2006 and 2005. Outstanding restricted stock
and unexercised stock options had no effect on diluted earnings
per share for the six-month period ended June 30, 2006.
F-20
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Comprehensive income includes net income and certain items
recorded directly to stockholders equity and classified as
other comprehensive income. The table below summarizes
comprehensive income and provides the components of the change
in accumulated other comprehensive income for the six-month
periods ended June 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Net Income
|
|
$
|
41,834
|
|
|
$
|
28,620
|
|
Other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
Derivative contracts settled and
reclassified, net of tax
|
|
|
8,926
|
|
|
|
10,892
|
|
Change in unrealized mark to
market gains/(losses) arising during period, net of tax
|
|
|
25,396
|
|
|
|
(29,626
|
)
|
|
|
|
|
|
|
|
|
|
Change in accumulated other
comprehensive income (loss)
|
|
|
34,322
|
|
|
|
(18,734
|
)
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
76,156
|
|
|
|
9,886
|
|
|
|
|
|
|
|
|
|
|
On August 7, 2006, the Company acquired the interest of BP
Exploration and Production Inc. (BP), in West
Cameron Block 110 and the southeast quarter of West Cameron
Block 111 in the Gulf of Mexico. The interest was acquired
by MERI exercising its preferential right to purchase. BP
retained its interest in depths below 15,000 feet. In the
Forest Transaction, the Company acquired MERIs previous
37.5% interest in the properties. As a result of the August 2006
acquisition, MERI owns 100% of the working interest, exclusive
of the deep rights retained by BP, and the Company became
operator of the interests owned by its subsidiary. The
acquisition cost, net of preliminary purchase price adjustments,
was approximately $70.9 million, which was financed by
borrowing under our senior secured credit facility. A
$10.4 million letter of credit under our senior secured
credit facility also was issued in favor of BP to secure
plugging and abandonment liabilities. The acquisition adds
proved reserves estimated by Mariner to be 20 Bcfe as of
August 1, 2006. Production associated with the acquired
interest was approximately 11 MMcfe/day during July 2006.
In October 2006, we announced that we made a material
conventional shelf discovery in the High Island 116 #5ST1 well,
drilled to a total measured depth of 14,683 feet / 13,150 feet
true vertical depth. The well encountered approximately 540 feet
of net true vertical depth pay in thirteen sands. We anticipate
completion and initial production in the fourth quarter of 2006.
High Island 116 is part of the Forest Gulf of Mexico operations
we acquired in March 2006. We have a 100% working interest and
an approximate 72% net revenue interest in the well.
|
|
12.
|
Supplemental
Guarantor Information
|
On April 24, 2006, the Company sold and issued to eligible
purchasers $300 million aggregate principal amount of its
71/2% senior
notes due 2013. The Notes are jointly and severally guaranteed
on a senior unsecured basis by the Companys existing and
future domestic subsidiaries (Subsidiary
Guarantors). In the future, the guarantees may be released
or terminated under certain circumstances. Each subsidiary
guarantee ranks senior in right of payment to any future
subordinated indebtedness of the guarantor subsidiary, ranks
equally in right of payment to all existing and future senior
unsecured indebtedness of the guarantor subsidiary and
effectively subordinate to all existing and future secured
indebtedness of the guarantor subsidiary, including its
guarantees of indebtedness under the Companys credit
facility, to the extent of the collateral securing such
indebtedness.
F-21
MARINER
ENERGY, INC.
NOTES TO
THE CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On March 2, 2006, a subsidiary of the Company completed a
merger transaction with Forest Energy Resources, Inc. Prior to
the transaction, Forest transferred and contributed the assets
of, and certain liabilities associated with, its Gulf of Mexico
operations to Forest Energy Resources, Inc. Immediately prior to
the merger, Forest distributed all of the outstanding shares of
Forest Energy Resources, Inc. to Forest shareholders on a pro
rata basis. Forest Energy Resources, Inc. then merged with a
newly formed subsidiary of Mariner, became a new wholly owned
subsidiary of Mariner and changed its name to MERI. The other
two guarantors were formed on December 29, 2004, did not
commence operations prior to January 1, 2005 and did not
have material operations in 2005. The net equity of the
guarantors was $0 as of December 31, 2004 and
December 31, 2005, therefore, historical information prior
to 2006 is not presented.
The following information sets forth our Condensed Consolidating
Statement of Operations for the six months ended
June 30, 2006, our Condensed Consolidating Balance Sheet as
of June 30, 2006 and our Condensed Consolidating Statement
of Cash Flows for the six months ended June 30, 2006.
Investments in our subsidiaries are accounted for on the equity
method; accordingly, entries necessary to consolidate the Parent
Company and the Subsidiary Guarantors are reflected in the
eliminations column. In the opinion of management, separate
complete financial statements of the Subsidiary Guarantors would
not provide additional material information that would be useful
in assessing their financial composition.
F-22
MARINER
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING BALANCE SHEET
As of
June 30, 2006
(Unaudited)
(In thousands except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
|
|
|
Mariner
|
|
|
|
Company
|
|
|
Guarantors
|
|
|
Eliminations
|
|
|
Energy, Inc.
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,656
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,656
|
|
Receivables, net
|
|
|
59,463
|
|
|
|
65,343
|
|
|
|
|
|
|
|
124,806
|
|
Prepaid expenses and other
|
|
|
42,506
|
|
|
|
64,128
|
|
|
|
|
|
|
|
106,634
|
|
Deferred tax asset
|
|
|
|
|
|
|
10,215
|
|
|
|
|
|
|
|
10,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
107,625
|
|
|
|
139,686
|
|
|
|
|
|
|
|
247,311
|
|
Property and
Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost
method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
757,860
|
|
|
|
1,144,132
|
|
|
|
|
|
|
|
1,901,992
|
|
Unproved, not subject to
amortization
|
|
|
93,266
|
|
|
|
117,994
|
|
|
|
|
|
|
|
211,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
851,126
|
|
|
|
1,262,126
|
|
|
|
|
|
|
|
2,113,252
|
|
Other property and equipment
|
|
|
13,318
|
|
|
|
280
|
|
|
|
|
|
|
|
13,598
|
|
Accumulated depreciation, depletion
and amortization
|
|
|
(155,689
|
)
|
|
|
(57,552
|
)
|
|
|
|
|
|
|
(213,241
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
708,755
|
|
|
|
1,204,854
|
|
|
|
|
|
|
|
1,913,609
|
|
Investment in
subsidiaries
|
|
|
922,531
|
|
|
|
|
|
|
|
(922,531
|
)
|
|
|
|
|
Intercompany
|
|
|
56,180
|
|
|
|
(56,180
|
)
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
|
|
|
|
261,472
|
|
|
|
|
|
|
|
261,472
|
|
Other Assets, Net of
Amortization
|
|
|
27,307
|
|
|
|
7,409
|
|
|
|
|
|
|
|
34,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
1,822,398
|
|
|
$
|
1,557,241
|
|
|
$
|
(922,531
|
)
|
|
$
|
2,457,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
10,540
|
|
|
$
|
47,134
|
|
|
$
|
|
|
|
$
|
57,674
|
|
Accrued liabilities
|
|
|
199,591
|
|
|
|
75,823
|
|
|
|
|
|
|
|
275,414
|
|
Accrued interest
|
|
|
4,131
|
|
|
|
697
|
|
|
|
|
|
|
|
4,828
|
|
Intercompany note
payable/(receivable)
|
|
|
(19,200
|
)
|
|
|
19,200
|
|
|
|
|
|
|
|
|
|
Derivative liability
|
|
|
8,158
|
|
|
|
13,242
|
|
|
|
|
|
|
|
21,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
203,220
|
|
|
|
156,096
|
|
|
|
|
|
|
|
359,316
|
|
Long-Term Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Abandonment liability
|
|
|
52,214
|
|
|
|
136,550
|
|
|
|
|
|
|
|
188,764
|
|
Deferred income tax
|
|
|
68,420
|
|
|
|
184,142
|
|
|
|
|
|
|
|
252,562
|
|
Derivative liability
|
|
|
4,262
|
|
|
|
|
|
|
|
|
|
|
|
4,262
|
|
Long term debt, revolving credit
facility
|
|
|
|
|
|
|
157,000
|
|
|
|
|
|
|
|
157,000
|
|
Long term debt, senior unsecured
notes
|
|
|
300,000
|
|
|
|
|
|
|
|
|
|
|
|
300,000
|
|
Note payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities
|
|
|
11,000
|
|
|
|
|
|
|
|
|
|
|
|
11,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
435,896
|
|
|
|
477,692
|
|
|
|
|
|
|
|
913,588
|
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders
Equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, $.0001 par
value; 180,000,000 shares authorized,
86,243,379 shares issued and outstanding at June 30,
2006
|
|
|
9
|
|
|
|
5
|
|
|
|
(5
|
)
|
|
|
9
|
|
Preferred stock, $.0001 par
value; 20,000,000 shares authorized, no shares issued and
outstanding at June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
paid-in-capital
|
|
|
1,055,412
|
|
|
|
886,142
|
|
|
|
(886,142
|
)
|
|
|
1,055,412
|
|
Accumulated other comprehensive loss
|
|
|
(8,073
|
)
|
|
|
922
|
|
|
|
|
|
|
|
(7,151
|
)
|
Accumulated retained earnings
|
|
|
135,934
|
|
|
|
36,384
|
|
|
|
(36,384
|
)
|
|
|
135,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,183,282
|
|
|
|
923,453
|
|
|
|
(922,531
|
)
|
|
|
1,184,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND
STOCKHOLDERS EQUITY
|
|
$
|
1,822,398
|
|
|
$
|
1,557,241
|
|
|
$
|
(922,531
|
)
|
|
$
|
2,457,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-23
MARINER
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the
six months ended June 30, 2006
(Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
|
|
|
Mariner
|
|
|
|
Company
|
|
|
Guarantors
|
|
|
Eliminations
|
|
|
Energy, Inc.
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
54,234
|
|
|
$
|
33,492
|
|
|
$
|
|
|
|
$
|
87,726
|
|
Gas sales
|
|
|
70,108
|
|
|
|
88,468
|
|
|
|
|
|
|
|
158,576
|
|
Other revenues
|
|
|
1,623
|
|
|
|
|
|
|
|
|
|
|
|
1,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
125,965
|
|
|
|
121,960
|
|
|
|
|
|
|
|
247,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
19,346
|
|
|
|
18,221
|
|
|
|
|
|
|
|
37,567
|
|
Transportation expense
|
|
|
1,527
|
|
|
|
750
|
|
|
|
|
|
|
|
2,277
|
|
General and administrative expense
|
|
|
16,666
|
|
|
|
807
|
|
|
|
|
|
|
|
17,473
|
|
Depreciation, depletion and
amortization
|
|
|
48,127
|
|
|
|
61,679
|
|
|
|
|
|
|
|
109,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
85,666
|
|
|
|
81,457
|
|
|
|
|
|
|
|
167,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
40,299
|
|
|
|
40,503
|
|
|
|
|
|
|
|
80,802
|
|
Earnings of
Affiliates
|
|
|
36,384
|
|
|
|
|
|
|
|
(36,384
|
)
|
|
|
|
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
249
|
|
|
|
|
|
|
|
|
|
|
|
249
|
|
Expense, net of amounts capitalized
|
|
|
(10,549
|
)
|
|
|
(4,119
|
)
|
|
|
|
|
|
|
(14,668
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
66,383
|
|
|
|
36,384
|
|
|
|
(36,384
|
)
|
|
|
66,383
|
|
Provision for income
taxes
|
|
|
(24,549
|
)
|
|
|
|
|
|
|
|
|
|
|
(24,549
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
41,834
|
|
|
$
|
36,384
|
|
|
$
|
(36,384
|
)
|
|
$
|
41,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
MARINER
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENT OF CASH FLOWS
For the
six months ended June 30, 2006
(Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Mariner
|
|
|
|
Company
|
|
|
Guarantors
|
|
|
Energy, Inc.
|
|
|
Net cash provided by operating
activities
|
|
$
|
85,078
|
|
|
$
|
11,017
|
|
|
$
|
96,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and
equipment
|
|
|
(143,156
|
)
|
|
|
(42,841
|
)
|
|
|
(185,997
|
)
|
Proceeds from property conveyances
|
|
|
2,012
|
|
|
|
|
|
|
|
2,012
|
|
Purchase price adjustment
|
|
|
|
|
|
|
(20,808
|
)
|
|
|
(20,808
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(141,144
|
)
|
|
|
(63,649
|
)
|
|
|
(204,793
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment of term note
|
|
|
(4,000
|
)
|
|
|
|
|
|
|
(4,000
|
)
|
Credit facility borrowings, net
|
|
|
(152,000
|
)
|
|
|
157,000
|
|
|
|
5,000
|
|
Debt and working capital acquired
from Forest Energy Resources, Inc.
|
|
|
|
|
|
|
(176,200
|
)
|
|
|
(176,200
|
)
|
Deferred offering costs
|
|
|
(12,129
|
)
|
|
|
|
|
|
|
(12,129
|
)
|
Net realized loss on derivative
contracts acquired
|
|
|
|
|
|
|
(3,548
|
)
|
|
|
(3,548
|
)
|
Proceeds from note offering
|
|
|
300,000
|
|
|
|
|
|
|
|
300,000
|
|
Proceeds from exercise of stock
options
|
|
|
675
|
|
|
|
|
|
|
|
675
|
|
Net activity in investments from
subsidiaries
|
|
|
(75,380
|
)
|
|
|
75,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
57,166
|
|
|
|
52,632
|
|
|
|
109,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Cash and Cash
Equivalents
|
|
|
1,100
|
|
|
|
|
|
|
|
1,100
|
|
Cash and Cash Equivalents at
Beginning of Period
|
|
|
4,556
|
|
|
|
|
|
|
|
4,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at
End of Period
|
|
$
|
5,656
|
|
|
$
|
|
|
|
$
|
5,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-25
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors & Stockholders
Mariner Energy, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of
Mariner Energy, Inc. (the Company) as of
December 31, 2005 and 2004 and the related consolidated
statements of operations, stockholders equity and
comprehensive income and cash flows for the year ended
December 31, 2005, for the period January 1, 2004
through March 2, 2004 (Pre-merger), for the period from
March 3, 2004 through December 31, 2004 (Post merger),
and for the year ended December 31, 2003 (Pre-merger).
These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our audits included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
Mariner Energy, Inc. as of December 31, 2005 and 2004, and
the results of its operations and cash flows for the year ended
December 31, 2005, for the period January 1, 2004
through March 2, 2004
(Pre-merger),
for the period from March 3, 2004 through December 31,
2004 (Post merger), and for the year ended December 31,
2003 (Pre-merger) in conformity with accounting principles
generally accepted in the United States of America.
The Company changed its method of accounting for asset
retirement obligations in 2003. This change is discussed in
Note 1 to the Consolidated Financial Statements.
As described in Note 1 to the Consolidated Financial
Statements, on March 2, 2004, Mariner Energy LLC, the
Companys parent company, merged with an affiliate of the
private equity funds Carlyle/Riverstone Global Energy and Power
Fund II, L.P. and ACON Investments LLC.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 30, 2006
(September 18, 2006 as to Note 13)
F-26
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands except share data)
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,556
|
|
|
$
|
2,541
|
|
Receivables, net of allowances of
$500 and $307 at December 31, 2005 and December 31,
2004, respectively
|
|
|
88,651
|
|
|
|
52,734
|
|
Deferred tax asset
|
|
|
26,017
|
|
|
|
|
|
Prepaid expenses and other
|
|
|
22,208
|
|
|
|
10,471
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
141,432
|
|
|
|
65,746
|
|
Property and
Equipment:
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost
method:
|
|
|
|
|
|
|
|
|
Proved
|
|
|
574,725
|
|
|
|
319,553
|
|
Unproved, not subject to
amortization
|
|
|
40,176
|
|
|
|
36,245
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
614,901
|
|
|
|
355,798
|
|
Other property and equipment
|
|
|
11,048
|
|
|
|
960
|
|
Accumulated depreciation, depletion
and amortization
|
|
|
(110,006
|
)
|
|
|
(52,985
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
515,943
|
|
|
|
303,773
|
|
Deferred Tax Asset
|
|
|
|
|
|
|
3,029
|
|
Other Assets, Net of
Amortization
|
|
|
8,161
|
|
|
|
3,471
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
665,536
|
|
|
$
|
376,019
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
37,530
|
|
|
$
|
2,526
|
|
Accrued liabilities
|
|
|
123,689
|
|
|
|
81,831
|
|
Accrued interest
|
|
|
614
|
|
|
|
79
|
|
Derivative liability
|
|
|
42,173
|
|
|
|
16,976
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
204,006
|
|
|
|
101,412
|
|
Long-Term Liabilities:
|
|
|
|
|
|
|
|
|
Abandonment liability
|
|
|
38,176
|
|
|
|
19,268
|
|
Deferred income tax
|
|
|
25,886
|
|
|
|
|
|
Derivative liability
|
|
|
21,632
|
|
|
|
5,432
|
|
Bank debt
|
|
|
152,000
|
|
|
|
105,000
|
|
Note payable
|
|
|
4,000
|
|
|
|
10,000
|
|
Other long-term liabilities
|
|
|
6,500
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
248,194
|
|
|
|
140,700
|
|
Commitments and Contingencies
(see Note 7)
|
|
|
|
|
|
|
|
|
Stockholders
Equity:
|
|
|
|
|
|
|
|
|
Common stock, $.0001 par
value; 70,000,000 shares authorized, 35,615,400 and
29,748,130 shares issued and outstanding at
December 31, 2005 and December 31, 2004, respectively
|
|
|
4
|
|
|
|
1
|
|
Additional
paid-in-capital
|
|
|
167,318
|
|
|
|
91,917
|
|
Unearned compensation
|
|
|
(6,613
|
)
|
|
|
|
|
Accumulated other comprehensive
(loss)
|
|
|
(41,473
|
)
|
|
|
(11,630
|
)
|
Accumulated retained earnings
|
|
|
94,100
|
|
|
|
53,619
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
213,336
|
|
|
|
133,907
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND
STOCKHOLDERS EQUITY
|
|
$
|
665,536
|
|
|
$
|
376,019
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial
statements
F-27
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands except share data)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
73,831
|
|
|
$
|
63,498
|
|
|
|
$
|
12,709
|
|
|
$
|
37,992
|
|
Gas sales
|
|
|
122,291
|
|
|
|
110,925
|
|
|
|
|
27,055
|
|
|
|
104,551
|
|
Other revenues
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
199,710
|
|
|
|
174,423
|
|
|
|
|
39,764
|
|
|
|
142,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
29,882
|
|
|
|
21,363
|
|
|
|
|
4,121
|
|
|
|
24,719
|
|
Transportation expense
|
|
|
2,336
|
|
|
|
1,959
|
|
|
|
|
1,070
|
|
|
|
6,252
|
|
General and administrative expense
|
|
|
37,053
|
|
|
|
7,641
|
|
|
|
|
1,131
|
|
|
|
8,098
|
|
Depreciation, depletion and
amortization
|
|
|
59,426
|
|
|
|
54,281
|
|
|
|
|
10,630
|
|
|
|
48,339
|
|
Derivative settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,222
|
|
Impairment of production equipment
held for use
|
|
|
1,845
|
|
|
|
957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
130,542
|
|
|
|
86,201
|
|
|
|
|
16,952
|
|
|
|
90,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
69,168
|
|
|
|
88,222
|
|
|
|
|
22,812
|
|
|
|
51,913
|
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
779
|
|
|
|
225
|
|
|
|
|
91
|
|
|
|
756
|
|
Expense, net of amounts capitalized
|
|
|
(8,172
|
)
|
|
|
(6,045
|
)
|
|
|
|
(5
|
)
|
|
|
(6,981
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
61,775
|
|
|
|
82,402
|
|
|
|
|
22,898
|
|
|
|
45,688
|
|
Provision for income
taxes
|
|
|
(21,294
|
)
|
|
|
(28,783
|
)
|
|
|
|
(8,072
|
)
|
|
|
(9,387
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect
of change in accounting method, net of tax effects
|
|
|
40,481
|
|
|
|
53,619
|
|
|
|
|
14,826
|
|
|
|
36,301
|
|
Cumulative effect of change in
accounting method, net of tax effects
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,943
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
40,481
|
|
|
$
|
53,619
|
|
|
|
$
|
14,826
|
|
|
$
|
38,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method, net of tax effects
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
.50
|
|
|
$
|
1.22
|
|
Cumulative effect of change in
accounting method, net of tax effects
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share
basic
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
.50
|
|
|
$
|
1.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method, net of tax effects
|
|
$
|
1.20
|
|
|
$
|
1.80
|
|
|
|
$
|
.50
|
|
|
$
|
1.22
|
|
Cumulative effect of change in
accounting method, net of tax effects
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share
diluted
|
|
$
|
1.20
|
|
|
$
|
1.80
|
|
|
|
$
|
.50
|
|
|
$
|
1.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding basic
|
|
|
32,667,582
|
|
|
|
29,748,130
|
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
Weighted average shares
outstanding diluted
|
|
|
33,766,577
|
|
|
|
29,748,130
|
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
The accompanying notes are an integral part of these financial
statements
F-28
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Other
|
|
|
Retained
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Unearned
|
|
|
Comprehensive
|
|
|
Earnings
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Compensation
|
|
|
Income (Loss)
|
|
|
(Deficit)
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
Balance at December 31,
2002
|
|
|
29,748
|
|
|
$
|
1
|
|
|
$
|
227,318
|
|
|
|
|
|
|
$
|
(14,177
|
)
|
|
$
|
(43,046
|
)
|
|
$
|
170,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,244
|
|
|
|
38,244
|
|
Change in fair value of derivative
hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39,280
|
|
|
|
|
|
|
|
39,280
|
|
Hedge settlements reclassified to
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,463
|
)
|
|
|
|
|
|
|
(29,463
|
)
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,061
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31,
2003
|
|
|
29,748
|
|
|
$
|
1
|
|
|
$
|
227,318
|
|
|
|
|
|
|
$
|
(4,360
|
)
|
|
$
|
(4,802
|
)
|
|
$
|
218,157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Merger Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,826
|
|
|
|
14,826
|
|
Change in fair value of derivative
hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,312
|
)
|
|
|
|
|
|
|
(7,312
|
)
|
Hedge settlements reclassified to
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(745
|
)
|
|
|
|
|
|
|
(745
|
)
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Merger Balance at March 2,
2004
|
|
|
29,748
|
|
|
$
|
1
|
|
|
$
|
227,318
|
|
|
|
|
|
|
$
|
(12,417
|
)
|
|
$
|
10,024
|
|
|
$
|
224,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(166,432
|
)
|
|
|
(166,432
|
)
|
Merger adjustments
|
|
|
|
|
|
|
|
|
|
|
(135,401
|
)
|
|
|
|
|
|
|
12,417
|
|
|
|
156,408
|
|
|
|
33,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at March 3,
2004
|
|
|
29,748
|
|
|
$
|
1
|
|
|
$
|
91,917
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
91,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53,619
|
|
|
|
53,619
|
|
Change in fair value of derivative
hedging instruments net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32,171
|
)
|
|
|
|
|
|
|
(32,171
|
)
|
Hedge settlements reclassified to
income net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,541
|
|
|
|
|
|
|
|
20,541
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31,
2004
|
|
|
29,748
|
|
|
$
|
1
|
|
|
$
|
91,917
|
|
|
|
|
|
|
$
|
(11,630
|
)
|
|
$
|
53,619
|
|
|
$
|
133,907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares issued
private equity offering
|
|
|
3,600
|
|
|
|
2
|
|
|
|
44,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,333
|
|
Common shares issued
restricted stock
|
|
|
2,267
|
|
|
|
1
|
|
|
|
31,741
|
|
|
|
(31,742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of unearned
compensation net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,129
|
|
|
|
|
|
|
|
|
|
|
|
25,129
|
|
Stock compensation
expense stock options net of income taxes
|
|
|
|
|
|
|
|
|
|
|
594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
594
|
|
Contributed capital
Mariner Energy, LLC and Mariner Holdings, Inc.
|
|
|
|
|
|
|
|
|
|
|
3,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,057
|
|
Merger adjustments
|
|
|
|
|
|
|
|
|
|
|
(4,322
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,322
|
)
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,481
|
|
|
|
40,481
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative
hedging instruments net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(61,878
|
)
|
|
|
|
|
|
|
(61,878
|
)
|
Hedge settlements reclassified to
income net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,035
|
|
|
|
|
|
|
|
32,035
|
|
Total comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31,
2005
|
|
|
35,615
|
|
|
$
|
4
|
|
|
$
|
167,318
|
|
|
$
|
(6,613
|
)
|
|
$
|
(41,473
|
)
|
|
$
|
94,100
|
|
|
$
|
213,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial
statements
F-29
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40,481
|
|
|
$
|
53,619
|
|
|
|
$
|
14,826
|
|
|
$
|
38,244
|
|
Adjustments to reconcile net income
to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax
|
|
|
21,294
|
|
|
|
27,162
|
|
|
|
|
8,072
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
60,640
|
|
|
|
55,067
|
|
|
|
|
10,630
|
|
|
|
48,414
|
|
Stock compensation expense
|
|
|
25,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedge activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,030
|
)
|
Impairment of production equipment
held for use
|
|
|
1,845
|
|
|
|
957
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of changes in
accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,988
|
)
|
Changes in operating assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(32,916
|
)
|
|
|
(10,615
|
)
|
|
|
|
(8,847
|
)
|
|
|
(3,599
|
)
|
Prepaid expenses and other
|
|
|
(5,201
|
)
|
|
|
(965
|
)
|
|
|
|
551
|
|
|
|
(2,257
|
)
|
Other assets
|
|
|
(184
|
)
|
|
|
321
|
|
|
|
|
(963
|
)
|
|
|
1,485
|
|
Accounts payable and accrued
liabilities
|
|
|
53,759
|
|
|
|
9,697
|
|
|
|
|
(3,974
|
)
|
|
|
1,208
|
|
Taxes payable to parent company and
deferred income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
165,444
|
|
|
|
135,243
|
|
|
|
|
20,295
|
|
|
|
88,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties
|
|
|
(237,729
|
)
|
|
|
(133,425
|
)
|
|
|
|
(15,264
|
)
|
|
|
(83,228
|
)
|
Proceeds from property conveyances
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
121,625
|
|
Additions to other property and
equipment
|
|
|
(10,088
|
)
|
|
|
(172
|
)
|
|
|
|
(78
|
)
|
|
|
(50
|
)
|
Restricted cash
|
|
|
|
|
|
|
620
|
|
|
|
|
1
|
|
|
|
14,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by
investing activities
|
|
|
(247,799
|
)
|
|
|
(132,977
|
)
|
|
|
|
(15,341
|
)
|
|
|
52,921
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Initial borrowings from revolving
credit facility, net of fees
|
|
|
|
|
|
|
131,579
|
|
|
|
|
|
|
|
|
|
|
Repayment of subordinated notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100,000
|
)
|
Repayment of term note
|
|
|
(6,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit facility borrowings
(repayments), net
|
|
|
47,000
|
|
|
|
(30,000
|
)
|
|
|
|
|
|
|
|
|
|
Proceeds from private equity
offering
|
|
|
44,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred offering costs
|
|
|
(3,840
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital contribution from affiliates
|
|
|
2,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend to Mariner Energy LLC
|
|
|
|
|
|
|
(166,432
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by
financing activities
|
|
|
84,370
|
|
|
|
(64,853
|
)
|
|
|
|
|
|
|
|
(100,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) in Cash and
Cash Equivalents
|
|
|
2,015
|
|
|
|
(62,587
|
)
|
|
|
|
4,954
|
|
|
|
41,830
|
|
Cash and Cash Equivalents at
Beginning of Period
|
|
|
2,541
|
|
|
|
65,128
|
|
|
|
|
60,174
|
|
|
|
18,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
at End of Period
|
|
$
|
4,556
|
|
|
$
|
2,541
|
|
|
|
$
|
65,128
|
|
|
$
|
60,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial
statements
F-30
MARINER
ENERGY, INC.
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
|
|
1.
|
Summary
of Significant Accounting Policies
|
Operations Mariner Energy, Inc. (the
Company) is an independent oil and gas exploration,
development and production company with principal operations in
the Gulf of Mexico, both shelf and deepwater, and the Permian
Basin in West Texas.
Organization On March 2, 2004, Mariner
Energy LLC, the parent company of Mariner Energy, Inc. (the
Company), merged with a subsidiary of MEI
Acquisitions Holdings, LLC, an affiliate of the private equity
funds Carlyle/Riverstone Global Energy and Power Fund II,
L.P. and ACON Investments LLC (the Merger). Prior to
the Merger, Joint Energy Development Investments Limited
Partnership (JEDI), which is an indirect
wholly-owned subsidiary of Enron Corp. (Enron),
owned approximately 96% of the common stock of Mariner Energy
LLC (see Note 2). In the Merger, all the shares of common
stock in Mariner Energy LLC were converted into the right to
receive cash and certain other consideration. As a result, JEDI
no longer owns any interest in Mariner Energy LLC, and the
Company is no longer affiliated with JEDI or Enron.
Simultaneously with the Merger, the Company obtained a revolving
line of credit with initial advances of $135 million from a
group of banks. The loan proceeds and an additional
$31.2 million of Company funds distributed to Mariner
Energy LLC were used to pay a portion of the gross Merger
consideration (which included repayment of $197.6 million
of Mariner Energy LLC debt outstanding at the time of the
Merger) and estimated transaction costs and expenses associated
with the Merger and bank financing. The Company also issued a
$10 million note and assigned a fully reserved receivable
valued at $1.9 million to JEDI as part of JEDIs
Merger consideration. In addition, pursuant to the Merger
agreement, JEDI agreed to indemnify the Company from certain
liabilities and the Company agreed to pay additional Merger
consideration contingent upon the outcome of a certain five well
drilling program that was completed in the second quarter of
2004. In September 2004, the Company paid approximately $161,000
as additional Merger consideration related to the five well
drilling program, and the Company believes it has fully
discharged its obligations thereunder.
The sources and uses of funds related to the Merger were as
follows:
|
|
|
|
|
Mariner Energy, Inc. bank loan
proceeds
|
|
$
|
135.0
|
|
Note payable issued by Mariner
Energy, Inc. to former parent
|
|
|
10.0
|
|
Equity from new owners
|
|
|
100.0
|
|
Distributions from Mariner Energy,
Inc.
|
|
|
31.2
|
|
Assignment by Mariner Energy, Inc.
of receivables
|
|
|
1.9
|
|
|
|
|
|
|
Total
|
|
$
|
278.1
|
|
|
|
|
|
|
Repayment of former parent debt
obligation
|
|
$
|
197.6
|
|
Merger consideration to
stockholders and warrant holders
|
|
|
73.5
|
|
Acquisition costs and other
expenses
|
|
|
7.0
|
|
|
|
|
|
|
Total
|
|
$
|
278.1
|
|
|
|
|
|
|
As a result of the change in control, accounting principles
generally accepted in the United States requires the Merger and
the resulting acquisition of Mariner Energy LLC by MEI
Acquisitions Holdings, LLC to be accounted for as a purchase
transaction in accordance with Statement of Financial Accounting
Standards No. 141, Business Combinations. Staff
Accounting bulletin No. 54 (SAB 54)
requires the application of push down accounting in
situations where the ownership of an entity has changed, meaning
that the post-transaction financial statements of the Company
reflect the new basis of accounting. Accordingly, the financial
F-31
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
statements as of December 31, 2004 reflect the
Companys fair value basis resulting from the acquisition
that has been pushed down to the Company. The aggregate purchase
price has been allocated to the underlying assets and
liabilities based upon the respective estimated fair values at
March 2, 2004 (date of Merger). The allocation of the
purchase price has been finalized. Carryover basis accounting
applies for tax purposes. Based on subsequent tax filings during
the year ended December 31, 2005, the Company recorded a
$4.3 million adjustment to the estimated tax basis at
acquisition. All financial information presented prior to
March 2, 2004 represents the basis of accounting used by
the pre-Merger entity. The period January 1, 2004 through
March 2, 2004 is referred to as 2004 Pre-Merger and the
period March 3, 2004 through December 31, 2004 is
referred to as 2004 Post-Merger.
The following table summarizes the estimated fair values of the
assets acquired and liabilities assumed at the March 2,
2004 acquisition:
ALLOCATION
OF PURCHASE PRICE TO MARINER ENERGY, INC.
|
|
|
|
|
|
|
March 2,
|
|
|
|
2004
|
|
|
|
(In millions)
|
|
|
Oil and natural gas
properties proved
|
|
$
|
203.5
|
|
Oil and natural gas
properties unproved
|
|
|
25.2
|
|
Other property and equipment and
other assets
|
|
|
0.7
|
|
Current assets
|
|
|
83.2
|
|
Deferred tax asset(1)
|
|
|
9.1
|
|
Other assets
|
|
|
4.6
|
|
Accounts payable and accrued
expenses
|
|
|
(62.2
|
)
|
Long-Term Liability
|
|
|
(14.7
|
)
|
Fair value of oil and natural gas
derivatives
|
|
|
(12.4
|
)
|
Debt
|
|
|
(145.0
|
)
|
|
|
|
|
|
Total Allocation
|
|
$
|
92.0
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents deferred income taxes recorded at the date of the
Merger due to differences between the book basis and the tax
basis of assets. For book purposes, we had a
step-up in
basis related to purchase accounting while our existing tax
basis carried over. |
The following reflects the unaudited pro forma results of
operations as though the Merger had been consummated at
January 1, 2004.
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Ending December 31,
|
|
|
|
2004
|
|
|
|
(In millions)
|
|
|
Revenues and other income
|
|
$
|
214.2
|
|
Income before taxes and change in
accounting method
|
|
|
103.0
|
|
Net income
|
|
|
67.0
|
|
F-32
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
On February 10, 2005, in anticipation of the Companys
private placement of 31,452,500 shares of common stock (the
Private Equity Offering), Mariner Holdings, Inc.
(the direct parent of Mariner Energy, Inc.) and Mariner Energy
LLC (the direct parent of Mariner Holdings, Inc.) were merged
into Mariner Energy, Inc. and ceased to exist. The mergers of
Mariner Holdings, Inc. and Mariner Energy LLC into the Company
had no operational or financial impact on the Company; however,
intercompany receivables of $0.2 million and
$2.9 million in cash held by the affiliates were
transferred to the Company in February 2005 and accounted for as
additional paid-in capital.
On March 2, 2006, the Company completed a merger
transaction with Forest Energy Resources, Inc. As a result of
this merger, the Company acquired the offshore Gulf of Mexico
operations of Forest Oil Corporation and amended and restated
its credit facility. See Note 9, Subsequent
Events.
Net Income Per Share Basic earnings per share
is calculated by dividing net income by the weighted average
number of shares of common stock outstanding during the period.
Fully diluted earnings per share assumes the conversion of all
potentially dilutive securities and is calculated by dividing
net income by the sum of the weighted average number of shares
of common stock outstanding plus all potentially dilutive
securities.
F-33
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
2004
|
|
|
|
|
|
|
Year Ended
|
|
|
through
|
|
|
through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands except per share data)
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method, net of tax effects
|
|
$
|
40,481
|
|
|
$
|
53,619
|
|
|
$
|
14,826
|
|
|
$
|
36,301
|
|
Cumulative effect of change in
accounting method, net of tax effects
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,943
|
|
Net income
|
|
$
|
40,481
|
|
|
$
|
53,619
|
|
|
$
|
14,826
|
|
|
$
|
38,244
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
32,668
|
|
|
|
29,748
|
|
|
|
29,748
|
|
|
|
29,748
|
|
Add dilutive securities
|
|
|
1,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total weighted average shares
outstanding and dilutive securities
|
|
|
33,767
|
|
|
|
29,748
|
|
|
|
29,748
|
|
|
|
29,748
|
|
Earnings per share
basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method, net of tax effects
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
$
|
0.50
|
|
|
$
|
1.22
|
|
Cumulative effect of change in
accounting method, net of tax effects
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.07
|
|
Net income per share
basic
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
$
|
0.50
|
|
|
$
|
1.29
|
|
Earnings per share
diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method, net of tax effects
|
|
$
|
1.20
|
|
|
$
|
1.80
|
|
|
$
|
0.50
|
|
|
$
|
1.22
|
|
Cumulative effect of change in
accounting method, net of tax effects
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.07
|
|
Net income per share
diluted
|
|
$
|
1.20
|
|
|
$
|
1.80
|
|
|
$
|
0.50
|
|
|
$
|
1.29
|
|
Effective March 3, 2005, we effected a stock split
increasing our authorized shares from 2,000,000 to 70,000,000
and our outstanding shares from 1,380 to 29,748,130. We also
changed the stated par value of our stock from $1 to
$.0001 per share. The accompanying financial and earnings
per share information has been restated utilizing the post-split
shares. Effective with our merger on March 2, 2004, all
company stock option plans and associated outstanding stock
options were canceled.
For the periods presented prior to 2005, Mariner Energy, Inc.
had no outstanding stock options so the basic and diluted
earnings per share were the same. In March 2005, 2,267,270
restricted stock awards were granted under the Equity
Participation Plan and 787,360 stock options were granted under
the Stock Incentive Plan. During the second and third quarters
of 2005, an additional 21,640 stock options were granted under
the Stock Incentive Plan for a total of 809,000 stock options
outstanding as of December 31, 2005. Outstanding restricted
stock and unexercised stock options diluted earnings by
$0.04 per share for the year ended December 31, 2005.
F-34
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Cash and Cash Equivalents All short-term,
highly liquid investments that have an original maturity date of
three months or less are considered cash equivalents.
Receivables Substantially all of the
Companys receivables arise from sales of oil or natural
gas, or from reimbursable expenses billed to the other
participants in oil and gas wells for which the Company serves
as operator. We routinely assess the recoverability of all
material trade and other receivables to determine their
collectibility. We accrue a reserve on a receivable when, based
on the judgment of management, it is probable that a receivable
will not be collected and the amount of the reserve may be
reasonably estimated.
Oil and Gas Properties Oil and gas properties
are accounted for using the full-cost method of accounting. All
direct costs and certain indirect costs associated with the
acquisition, exploration and development of oil and gas
properties are capitalized. Amortization of oil and gas
properties is provided using the
unit-of-production
method based on estimated proved oil and gas reserves. No gains
or losses are recognized upon the sale or disposition of oil and
gas properties unless the sale or disposition represents a
significant quantity of oil and gas reserves, which would have a
significant impact on the depreciation, depletion and
amortization rate.
Under full cost accounting rules, total capitalized costs are
limited to a ceiling equal to the present value of future net
revenues, discounted at 10% per annum, plus the lower of cost or
fair value of unproved properties less income tax effects (the
ceiling limitation). We perform a quarterly ceiling
test to evaluate whether the net book value of our full cost
pool exceeds the ceiling limitation. If capitalized costs (net
of accumulated depreciation, depletion and amortization) less
related deferred taxes are greater than the discounted future
net revenues or ceiling limitation, a write-down or impairment
of the full cost pool is required. A write-down of the carrying
value of the full cost pool is a non-cash charge that reduces
earnings and impacts stockholders equity in the period of
occurrence and typically results in lower depreciation,
depletion and amortization expense in future periods. Once
incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices
in effect as of the balance sheet date and adjusted for
basis or location differential, held constant over
the life of the reserves. We use derivative financial
instruments that qualify for cash flow hedge accounting under
SFAS 133 to hedge against the volatility of natural gas
prices and, in accordance with SEC guidelines, we include
estimated future cash flows from our hedging program in our
ceiling test calculation. In addition, subsequent to the
adoption of SFAS 143, Accounting for Asset Retirement
Obligations, the future cash outflows associated with
settling asset retirement obligations are not included in the
computation of the discounted present value of future net
revenues for the purposes of the ceiling test calculation.
Unproved Properties The costs associated with
unevaluated properties and properties under development are not
initially included in the full cost amortization base and relate
to unproved leasehold acreage, seismic data, wells and
production facilities in progress and wells pending
determination together with interest costs capitalized for these
projects. Unevaluated leasehold costs are transferred to the
amortization base once determination has been made or upon
expiration of a lease. Geological and geophysical costs,
including
3-D seismic
data costs, are included in the full cost amortization base as
incurred when such costs cannot be associated with specific
unevaluated properties for which we own a direct interest.
Seismic data costs are associated with specific unevaluated
properties if the seismic data is acquired for the purpose of
evaluating acreage or trends covered by a leasehold interest
owned by us. We make this determination based on an analysis of
leasehold and seismic maps and discussions with our Chief
Exploration Officer. Geological and geophysical costs included
in unproved properties are transferred to the full cost
F-35
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
amortization base along with the associated leasehold costs on a
specific project basis. Costs associated with ells in progress
and wells pending determination are transferred to the
amortization base once a determination is made whether or not
proved reserves can be assigned to the property. Costs of dry
holes are transferred to the amortization base immediately upon
determination that the well is unsuccessful. All items included
in our unevaluated property balance are assessed on a quarterly
basis for possible impairment or reduction in value.
Other Property and Equipment Depreciation of
other property and equipment is provided on a straight-line
basis over their estimated useful lives, which range from three
to twenty-two years.
Prepaid Expenses and Other Prepaid expenses
and other includes $3.3 million of oil and gas lease and
well equipment held in inventory at December 31, 2005. In
2005 and 2004, we reduced the carrying cost of our inventory by
$1.8 million and $1.0 million, respectively, to
account for a reduction in the estimated value, primarily
related to subsea trees and wellhead equipment held in
inventory. Other current assets at December 31, 2005 also
include prepaid insurance and seismic costs of
$13.9 million and deferred offering costs of
$3.8 million related to the merger with Forest Energy
Resources.
Other Assets Other assets as of
December 31, 2005 were primarily comprised of
$1.4 million of amortizable bank fees, $2.3 million in
non-current receivables and $4.3 million of prepaid seismic
costs. Other assets as of December 31, 2004 were primarily
comprised of $2.5 million of amortizable bank fees and
various deposits held by third parties. Accumulated amortization
as of December 31, 2005 and 2004 was $2.1 million and
$0.9 million, respectively.
Production Costs All costs relating to
production activities, including workover costs incurred to
maintain production, are charged to expense as incurred.
General and Administrative Costs and Expenses
Under the full cost method of accounting, a portion of our
general and administrative expenses that are attributable to our
acquisition, exploration and development activities are
capitalized as part of our full cost pool. These capitalized
costs include salaries, employee benefits, costs of consulting
services and other costs directly identified with acquisition
exploration and development activities. We capitalized general
and administrative costs related to our acquisition, exploration
and development activities, during 2005, 2004 and 2003 of
$5.3 million, $6.9 million and $6.6 million,
respectively.
We receive reimbursement for administrative and overhead
expenses incurred on behalf of other working interest owners on
properties we operate. These reimbursements totaling
$6.9 million, $4.4 million and $1.8 million for
the years ended December 31, 2005, 2004 and 2003,
respectively, were allocated as reductions to general and
administrative expenses incurred. Generally, we do not receive
any reimbursements or fees in excess of the costs incurred;
however, if we did, we would credit the excess to the full cost
pool to be recognized through lower cost amortization as
production occurs.
Income Taxes The Companys taxable
income is included in a consolidated United States income tax
return with Mariner Energy LLC. In February 2005, Mariner Energy
LLC was merged into Mariner Energy, Inc. Following the effective
date of that merger through March 2006, Mariner Energy, Inc.
will file its own income tax return. After the Forest merger in
March 2006 merger, the Companys taxable income will be
included in a consolidated United States income tax return with
Forest Energy Resources and the Companys other
subsidiaries. The intercompany tax allocation policy provides
that each member of the consolidated group compute a provision
for income taxes on a separate return basis. The Company records
its income taxes using an asset and liability approach which
results in the recognition of deferred tax assets and
liabilities for the expected future tax consequences of
temporary differences between the book carrying amounts and the
tax
F-36
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
bases of assets and liabilities. Valuation allowances are
established when necessary to reduce deferred tax assets to the
amount more likely than not to be recovered.
Capitalized Interest Costs The Company
capitalizes interest based on the cost of major development
projects which are excluded from current depreciation,
depletion, and amortization calculations. Capitalized interest
costs were approximately $0.7 million for 2005, $0.4 and
$-0- million for 2004 Post-merger and 2004 Pre-merger,
respectively, and $0.7 million for 2003.
Accrual for Future Abandonment Costs
Statement of Financial Accounting Standards (SFAS) No. 143,
Accounting for Asset Retirement Obligations,
addresses accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 was
adopted on January 1, 2003. SFAS No. 143 requires
that the fair value of a liability for an assets
retirement obligation be recorded in the period in which it is
incurred and the corresponding cost capitalized by increasing
the carrying amount of the related long-lived asset. The
liability is accreted to its then present value each period, and
the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other
than the recorded amount, a gain or loss is recognized.
The adoption of SFAS 143 resulted in a January 1, 2003
cumulative effect adjustment to record (i) an
$11.3 million increase in the carrying values of proved
properties, and (ii) a $4.5 million increase in
current abandonment liabilities. The net impact of these items
was to record a pre-tax gain of $3.0 million as a
cumulative effect adjustment of a change in accounting principle
in the Companys statements of operations upon adoption on
January 1, 2003.
The following roll forward is provided as a reconciliation of
the beginning and ending aggregate carrying amounts of the asset
retirement obligation.
|
|
|
|
|
|
|
(In millions)
|
|
|
Abandonment liability as of
January 1, 2004 (Pre-Merger)
|
|
$
|
15.0
|
|
Liabilities Incurred
|
|
|
|
|
Claims Settled
|
|
|
(1.5
|
)
|
Accretion Expense
|
|
|
0.2
|
|
|
|
|
|
|
Abandonment Liability as of
March 2, 2004 (Pre-merger)
|
|
$
|
13.7
|
|
|
|
|
|
|
Abandonment Liability as of
March 3, 2004 (Post-merger)
|
|
$
|
13.7
|
|
Liabilities Incurred
|
|
|
11.5
|
|
Claims Settled
|
|
|
(2.7
|
)
|
Accretion Expense
|
|
|
1.5
|
|
|
|
|
|
|
Abandonment Liability as of
December 31, 2004 (Post-merger)(1)
|
|
$
|
24.0
|
|
|
|
|
|
|
Liabilities Incurred
|
|
|
28.6
|
|
Claims Settled
|
|
|
(5.5
|
)
|
Accretion Expense
|
|
|
2.4
|
|
|
|
|
|
|
Abandonment Liability as of
December 31, 2005 (Post-merger)(2)
|
|
$
|
49.5
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $4.7 million classified as a current accrued
liability at December 31, 2004. |
|
(2) |
|
Includes $11.4 million classified as a current accrued
liability at December 31, 2005. |
F-37
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Hedging Program The Company utilizes
derivative instruments in the form of natural gas and crude oil
price swap agreements and costless collar arrangements in order
to manage price risk associated with future crude oil and
natural gas production and fixed-price crude oil and natural gas
purchase and sale commitments. Such agreements are accounted for
as hedges using the deferral method of accounting. Gains and
losses resulting from these transactions, recorded at market
value, are deferred and recorded in Accumulated Other
Comprehensive Income (AOCI) as appropriate, until
recognized as operating income in the Companys Statement
of Operations as the physical production hedged by the contracts
is delivered.
The net cash flows related to any recognized gains or losses
associated with these hedges are reported as oil and gas
revenues and presented in cash flows from operations. If the
hedge is terminated prior to expected maturity, gains or losses
are deferred and included in income in the same period as the
physical production hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify
as a cash flow hedge are the following: (i) the item to be
hedged exposes the Company to price risk; (ii) the
derivative reduces the risk exposure and is designated as a
hedge at the time the derivative contract is entered into; and
(iii) at the inception of the hedge and throughout the
hedge period there is a high correlation of changes in the
market value of the derivative instrument and the fair value of
the underlying item being hedged.
When the designated item associated with a derivative instrument
matures, is sold, extinguished or terminated, derivative gains
or losses are recognized as part of the gain or loss on sale or
settlement of the underlying item. When a derivative instrument
is associated with an anticipated transaction that is no longer
expected to occur or if correlation no longer exists, the gain
or loss on the derivative is recognized in income to the extent
the future results have not been offset by the effects of price
or interest rate changes on the hedged item since the inception
of the hedge.
Revenue Recognition We use the entitlements
method of accounting for the recognition of natural gas and oil
revenues. Under this method of accounting, income is recorded
based on our net revenue interest in production or nominated
deliveries. We incur production gas volume imbalances in the
ordinary course of business. Net deliveries in excess of
entitled amounts are recorded as liabilities, while net under
deliveries are reflected as assets. Imbalances are reduced
either by subsequent recoupment of
over-and-under
deliveries or by cash settlement, as required by applicable
contracts. Production imbalances are
marked-to-market
at the end of each month at the lowest of (i) the price in
effect at the time of production; (ii) the current market
price; or (iii) the contract price, if a contract is in
hand.
The Companys gas balancing assets and liabilities are not
material as oil and gas volumes sold are not significantly
different from the Companys share of production.
Financial Instruments The Companys
financial instruments consist of cash and cash equivalents,
receivables, payables and outstanding debt. The carrying amount
of the Companys other instruments noted above approximate
fair value due to the short-term nature of these investments.
The carrying amount of our long-term debt approximates fair
value as the interest rates are generally indexed to current
market rates.
Use of Estimates in the Preparation of Financial
Statements The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amount of revenues and expenses during the reporting
period. Actual results could differ from these estimates.
F-38
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Major Customers During the twelve months
ended December 31, 2005, sales of oil and gas to three
purchasers accounted for 24%, 10% and 15% of total revenues.
During the year ended December 31, 2004, sales of oil and
gas to three purchasers, including an Enron affiliate, accounted
for 27%, 18% and 12% of total revenues. During the year ended
December 31, 2003, sales of oil and gas to three
purchasers, including an Enron affiliate, accounted for 34%, 19%
and 14% of total revenues. Management believes that the loss of
any of these purchasers would not have a material impact on the
Companys financial condition, results of operations or
cash flows.
Stock Options The Company (as allowed by
SFAS No. 123 Accounting for Stock Based
Compensation as amended by SFAS No. 148
Accounting for Stock-Based Compensation
Transition and Disclosure) has historically applied APB
Opinion No. 25 Accounting for Stock Issued to
Employees for its grants made pursuant to its employee
stock option plans. The Company applies APB Opinion 25 and
related interpretations in accounting for the Stock Option Plan.
Accordingly, no compensation cost has been recognized for the
Stock Option Plan. Had compensation cost for the Stock Option
Plan been determined based on the fair value at the grant date
for awards under the Stock Option Plan consistent with the
method of SFAS No. 123, the Companys net income
for the years ended December 31, 2004 and 2003 would not
have changed.
Effective January 1, 2005, we adopted the fair value
expense recognition provisions of SFAS 123(R). Using the
modified retrospective application, the Company would be
required to give effect to the fair-value based method of
accounting for awards granted, modified, or settled in cash in
fiscal years beginning after December 15, 1994 on a basis
consistent with the pro forma disclosures required for those
periods by Statement 123, as amended by FASB Statement
No. 14 Accounting for Stock Based
Compensation Transition and Disclosure. Since
the Company had no employee stock options plans in effect at
January 1, 2005, adoption of this method is expected to
have no impact on historical information presented by the
Company.
As a result of the adoption of the above described
SFAS No. 123(R), we recorded compensation expense for
the fair value of restricted stock that was granted pursuant to
our Equity Participation Plan (see Management of
Mariner Equity Participation Plan) and for
subsequent grants of stock options or restricted stock made
pursuant to the Mariner Energy, Inc. Stock Incentive Plan (see
Management of Mariner Stock Incentive
Plan). We recorded compensation expense for the
restricted stock grants equal to their fair value at the time of
the grant, amortized pro rata over the restricted period.
General and administrative expense for the year ended
December 31, 2005 includes $25.7 million of
compensation expense related to restricted stock granted in 2005
and $0.6 million of compensation expense related to stock
options outstanding as of December 31, 2005. For the year
ended December 31, 2004, we recorded no stock compensation
expense related to either restricted stock or stock options.
Recent Accounting Pronouncements In December
2004, the Financial Accounting Standards Board
(FASB) issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an Amendment of APB
Opinion No. 29, which provides that all nonmonetary
asset exchanges that have commercial substance must be measured
based on the fair value of the assets exchanged and any
resulting gain or loss recorded. An exchange is defined as
having commercial substance if it results in a significant
change in expected future cash flows. Exchanges of operating
interests by oil and gas producing companies to form a joint
venture continue to be exempted. APB Opinion No. 29
previously exempted all exchanges of similar productive assets
from fair value accounting, therefore resulting in no gain or
loss recorded for such exchanges. SFAS No. 153 became
effective for fiscal periods beginning on or after June 15,
2005. Accordingly, we adopted this statement effective
June 30, 2005
F-39
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
and it did not have a material impact on our consolidated
financial position, results of operations or cash flows.
In March 2005, the FASB issued Interpretation (FIN)
No. 47, Accounting for Conditional Asset
Retirement Obligations, which clarifies that an entity
is required to recognize a liability for the fair value of a
conditional asset retirement obligation when the obligation is
incurred generally upon acquisition, construction,
or development
and/or
through the normal operation of the asset, if the fair value of
the liability can be reasonably estimated. A conditional asset
retirement obligation is a legal obligation to perform an asset
retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. Uncertainty
about the timing
and/or
method of settlement is required to be factored into the
measurement of the liability when sufficient information exists.
We adopted FIN No. 47 on December 31, 2005 and it
did not have a material impact on our consolidated financial
position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections a
replacement of APB Opinion No. 20 and FASB Statement
No. 3. SFAS No. 154 changes the
requirements for the accounting and reporting of a change in
accounting principle, including voluntary changes in accounting
principle and changes required by an accounting pronouncement
that does not include specific transition provisions.
SFAS No. 154 requires retrospective application to
prior period financial statements of changes in accounting
principle. If impractical to determine either the
period-specific effects or the cumulative effect of the change,
the new accounting principle would be applied as if it were
adopted prospectively from the earliest date practical. The
correction of errors in prior period financial statements should
be identified as a restatement.
SFAS No. 154 is effective for fiscal years beginning
after December 15, 2005. Accordingly, adopted this
statement effective January 1, 2006 and, upon adoption, it
did not have a material impact on our consolidated financial
position, results of operations or cash flows.
In September 2005, the Emerging Issues Task Force (EITF) reached
a consensus on Issue
No. 04-13,
Accounting for Purchases and Sales of Inventory with the
Same Counterparty. EITF
Issue 04-13
requires that purchases and sales of inventory with the same
counterparty in the same line of business should be accounted
for as a single non-monetary exchange, if entered into in
contemplation of one another. The consensus is effective for
inventory arrangements entered into, modified or renewed in
interim or annual reporting periods beginning after
March 15, 2006. We do not expect the adoption of this EITF
Issue to have a material impact on our consolidated financial
position, results of operations or cash flows.
In February 2006, the FASB issued SFAS No. 155,
Accounting for Certain Hybrid Financial
Instruments an amendment of FASB Statements
No. 133 and 140. SFAS No. 155 simplifies
the accounting for certain hybrid financial instruments,
eliminates the FASBs interim guidance which provides that
beneficial interests in securitized financial assets are not
subject to the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, and eliminates the restriction on the passive
derivative instruments that a qualifying special-purpose entity
may hold. SFAS No. 155 is effective for all financial
instruments acquired or issued after the beginning of an
entitys first fiscal year that begins after
September 15, 2006. We do not expect this Statement to have
a material impact on our consolidated financial position,
results of operations or cash flows.
|
|
2.
|
Related
Party Transactions
|
Organization and Ownership of the Company
Until February 10, 2005, the Company was a wholly-owned
subsidiary of Mariner Holdings, Inc., which was a wholly-owned
subsidiary of Mariner Energy LLC.
F-40
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
From April 1, 1996, until October 1998, Mariner Holdings,
Inc. was a majority-owned subsidiary of JEDI, an affiliate of
Enron. In October 1998, JEDI and other stockholders of Mariner
Holdings, Inc. exchanged all of their common shares of Mariner
Holdings, Inc. for an equivalent ownership percentage in Mariner
Energy LLC. From October 1998 until the Merger, Mariner Energy
LLC was a majority-owned subsidiary of JEDI.
During the period of JEDIs ownership of the Company,
Mariner Energy LLC and the Company entered into various
financing and operating transactions, such as oil and gas sale
transactions, commodity price hedge transactions, and financial
transactions with affiliates of Enron. Below is a summary of key
transactions between the Company or Mariner Energy LLC and
Enron-affiliated entities.
On February 10, 2005, in anticipation of the Private Equity
Offering, Mariner Holdings, Inc. (the direct parent of Mariner
Energy, Inc.) and Mariner Energy LLC (the direct parent of
Mariner Holdings, Inc.) were merged into Mariner Energy, Inc.
and ceased to exist. The mergers of Mariner Holdings, Inc. and
Mariner Energy LLC into the Company had no operational or
financial impact on the Company.
Mariner
Energy LLC
Enron Affiliate Term Loan In March 2000,
Mariner Energy LLC established an unsecured term loan with Enron
North America Corp. (ENA), an affiliate of Enron, to
repay amounts outstanding under various affiliate credit
facilities at Mariner Energy LLC and the Company and provide
additional working capital. The loan bore interest at 15%, which
interest accrued and was added to the loan principal. In
conjunction with the loan, warrants were issued to ENA providing
the right to purchase up to 900,000 common shares of Mariner
Energy LLC for $0.01 per share. The loan and warrants were
subsequently assigned by ENA to another Enron affiliate. In
connection with the Merger, the loan balance, which was
approximately $192.8 million as of December 31, 2003,
was repaid in full, and the warrants were exercised and the
holders received their pro rata portion of the Merger
consideration.
Mariner
Energy, Inc.
As of March 2, 2004 the Company is no longer affiliated
with Enron.
Oil and Gas Production Sales to Enron
Affiliates During the years ending
December 31, 2004 and 2003, sales of oil and gas production
to Enron affiliates were $62.6 million and
$32.6 million, respectively. These sales were generally
made on one to three month contracts. At the time Enron filed
its petition for bankruptcy protection in December 2001, the
Company immediately ceased selling its physical production to
Enron Upstream Company, LLC, an Enron affiliate; however, it
continued to sell its production to Bridgeline Gas Marketing,
LLC, another Enron affiliate. No default in payment by
Bridgeline has occurred. As of December 31, 2001, after
Enron filed for bankruptcy protection, the Company had an
outstanding receivable of $3.0 million from ENA Upstream
related to sales of production. This amount was not paid as
scheduled. In 2001, we fully allowed for its uncollectability
and reduced the outstanding receivable to $-0-. The Company
submitted a proof of claim to the bankruptcy court presiding
over the Enron bankruptcy for amounts owed to it by ENA
Upstream. As part of the Merger consideration, the Company
assigned this and another receivable to JEDI at an agreed value
of approximately $1.9 million.
Price Risk Management Activities The Company
engages in price risk management activities from time to time.
These activities are intended to manage its exposure to
fluctuations in commodity prices for natural gas and crude oil.
The Company primarily utilizes price swaps as a means to manage
such risk. Prior to the Enron bankruptcy, all of the
Companys hedging contracts were with ENA. As a result of
ENAs
F-41
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
bankruptcy, the November 2001 through April 30, 2002
settlements for oil and gas were not paid when due. On
May 14, 2002, the Company elected under its ISDA Master
Agreement with ENA to terminate all open hedge contracts. The
effect of this termination was to fix the nominal value on all
remaining contracts on May 14, 2002. Subsequent to this
termination, the value of all oil and natural gas unpaid hedge
contracts was $7.7 million. In accordance with Statement of
Financial Accounting Standards (SFAS) No. 133
Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS No. 137 and
No. 138, the Company de-designated its contracts effective
December 2, 2001 and recognized all market value changes
subsequent to such de-designation in its earnings. The value
recorded up to the time of de-designation and included in
Accumulated Other Comprehensive Income (AOCI) was
reclassified out of AOCI and into earnings as the original
corresponding production, as hedged by the contracts was
produced. As of December 31, 2003, approximately
$25.8 million was reclassified to earnings.
As of March 2, 2004 the Company is no longer affiliated
with ENA. The following table sets forth the results of hedging
transactions during the periods indicated that were made with
ENA (all amounts shown are non-cash items):
|
|
|
|
|
|
|
|
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
|
2004
|
|
|
2003
|
|
|
Natural gas quantity hedged (MMbtu)
|
|
|
|
|
|
|
3,650,000
|
|
Increase (decrease) in natural gas
sales (thousands)
|
|
|
|
|
|
$
|
2,603
|
|
Crude oil quantity hedged (MBbls)
|
|
|
|
|
|
|
|
|
Increase (decrease) in crude oil
sales (thousands)
|
|
|
|
|
|
|
|
|
Supplemental ENA Affiliate Data provided
below is supplemental balance sheet and income statement
information for affiliate entities reflecting net balances, net
of any allowances:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2004
|
|
|
2003
|
|
|
|
(Amount in millions)
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
Related Party Receivable:
|
|
|
|
|
|
|
|
|
Derivative Asset
|
|
$
|
|
|
|
$
|
|
|
Settled Hedge Receivable
|
|
|
|
|
|
|
|
|
Oil and Gas Receivable
|
|
|
|
|
|
|
|
|
Accrued Liabilities:
|
|
|
|
|
|
|
|
|
Transportation Contract
|
|
|
|
|
|
|
0.1
|
|
Service Agreement
|
|
|
|
|
|
|
0.4
|
|
Stockholders Equity:
|
|
|
|
|
|
|
|
|
Common Stock
|
|
$
|
|
|
|
$
|
.001
|
|
Additional Paid in Capital
|
|
|
|
|
|
|
227.3
|
|
Accumulated other Comprehensive
Income
|
|
$
|
|
|
|
$
|
227.3
|
|
F-42
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2004
|
|
|
2003
|
|
|
Income Statement Data
|
|
|
|
|
|
|
|
|
Oil and Gas Sales
|
|
$
|
|
|
|
$
|
32.6
|
|
General and Administrative Expenses
|
|
|
|
|
|
|
0.4
|
|
Transportation Expenses
|
|
|
|
|
|
|
1.9
|
|
Unrealized gain and other non-cash
derivative instrument adjustments
|
|
|
|
|
|
|
|
|
Post-Merger
Related Party Transactions
In connection with the Merger, Mariner Energy LLC entered into
management agreements with two affiliates of MEI Acquisitions
Holdings, LLC, the Companys post-Merger parent company.
These agreements provided for the payment by Mariner Energy LLC
of an aggregate of $2.5 million to the affiliates in
connection with the provision of management services. Such
payments have been made. Mariner Energy LLC also entered into
monitoring agreements with two affiliates of MEI Acquisitions
Holdings, LLC, providing for the payment by Mariner Energy LLC
of an aggregate of one percent of its annual EBITDA to the
affiliates in connection with certain monitoring activities.
Under the terms of the monitoring agreements, the affiliates
provided financial advisory services in connection with the
ongoing operations of Mariner subsequent to the Merger.
Effective February 7, 2005, these contracts were terminated
in consideration of lump sum cash payments by Mariner totalling
$2.3 million. The Company recorded the termination payments
as general and administrative expenses for the year ended
December 31, 2005.
In March 2003, the Company sold its remaining 25% working
interest in its Falcon and Harrier discoveries and surrounding
blocks, located in East Breaks area in the western Gulf of
Mexico, for $121.6 million. The Company retained a
41/4 percent
overriding royalty interest on seven non-producing blocks. The
proceeds from the sale were used for debt reduction, capital
expenditures, and other corporate purposes. At March 31,
2003, the Falcon and Harrier projects had approximately
44 Bcfe assigned as proven oil and gas reserves to the
Companys interest. No gain or loss was recognized as a
result of this sale, as the sale did not significantly affect
the Companys depletion rate.
Bank Credit Facility On March 2, 2004,
simultaneously with the closing of the Merger, the Company
obtained a revolving line of credit with initial advances of
$135 million from a group of seven banks (since reduced to
six banks) led by Union Bank of California, N.A. and BNP
Paribas. Proceeds of these advances were used to pay a portion
of the Merger consideration (which included repayment of the
debt of Mariner Energy LLC) and transaction costs and
expenses associated with the Merger. The bank credit facility
provides up to $150 million of revolving borrowing
capacity, subject to a borrowing base, and a $25 million
term loan. The initial advance was made in two tranches: a
$110 million Tranche A and a $25 million
Tranche B.
The Tranche A revolving note matures on March 2, 2007.
The borrowing capacity under the Tranche A note is subject
to a borrowing base initially set at $110 million. The
borrowing base initially is subject to
F-43
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
redetermination by the lenders quarterly. After the
Tranche B note is repaid, provided that at least
$10 million of unused availability exists under
Tranche A, the borrowing base will be redetermined
semi-annually. The borrowing base is based upon the evaluation
by the lenders of the Companys oil and gas reserves and
other factors. Any increase in the borrowing base requires the
consent of all lenders. On August 5, 2005, the lenders
agreed to increase the borrowing base to $170 million. On
January 20, 2006, the lenders agreed to increase the
borrowing base to $185 million.
Borrowings under the Tranche A note bear interest, at the
option of the Company, at a rate of (i) LIBOR plus 2.00% to
2.75% depending upon utilization, or (ii) the greater of
(a) the Federal Funds Rate plus 0.50% or (b) the
Reference Rate (prime rate), plus 0.00% to 0.50% depending upon
utilization.
Borrowings under the Tranche B note bear interest at a rate
equal to the greater of (a) the Federal Funds Rate plus
0.50% or (b) the Reference Rate, plus 3.00%. In July 2004
(prior to its December 2, 2004 maturity date) the
outstanding Tranche B note was converted to a
Tranche A note, and all subsequent advances under the
credit facility are Tranche A advances. Once repaid, the
Tranche B advances may not be reborrowed.
Substantially all of the Companys assets, other than the
assets securing the term promissory note issued to JEDI, are
pledged to secure the bank credit facility. The Company must pay
a commitment fee of 0.25% to 0.50% per year on the unused
availability under the bank credit facility, depending upon
utilization.
The bank credit facility contains various restrictive covenants
and other usual and customary terms and conditions of a
revolving bank credit facility, including limitations on the
payment of cash dividends and other restricted payments,
limitations on the incurrence of additional debt, prohibitions
on the sale of assets, and requirements for hedging a portion of
the Companys oil and natural gas production. Financial
covenants require the Company to, among other things:
|
|
|
|
|
maintain a ratio, as of the last day of each fiscal quarter, of
(a) current assets (excluding cash posted as collateral to
secure hedging obligations) plus unused availability under the
credit facility to (b) current liabilities (excluding the
current portion of debt and the current portion of hedge
liabilities) of not less than (i) 0.75 to 1.00 until
June 30, 2004 and (ii) 1.00 to 1.00 thereafter;
|
|
|
|
maintain a ratio, as of the last day of each fiscal quarter, of
(a) EBITDA (earnings before interest, taxes, depreciation,
amortization and depletion) to (b) the sum of interest
expense and maintenance capital expenditures for the period and
20% (on an annualized basis) of outstanding Tranche A
advances, of not less than 1.20 to 1.00; and
|
|
|
|
maintain a ratio, as of the last day of each fiscal quarter, of
(a) total debt to (b) EBITDA of not greater than 1.75
to 1.00 prior to the issuance by the Company of bonds as
described in the credit agreement and 3.00 to 1.00 thereafter.
|
The bank credit facility also contains customary events of
default, including the occurrence of a change of control or
default in the payment or performance of any other indebtedness
equal to or exceeding $2.0 million.
In connection with the merger with Forest Energy Resources on
March 2, 2006, the Company amended and restated the
existing bank credit facility to, among other things, increase
maximum credit availability to $500 million, with a
$400 million borrowing base as of that date, add an
additional dedicated $40 million letter of credit facility,
and add Mariner Energy Resources, Inc. as a co-borrower. Please
see Note 9,
F-44
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Subsequent Events. The financial covenants
were modified under the amended and restated bank credit
facility to require the Company to, among other things:
|
|
|
|
|
maintain a ratio of consolidated current assets plus the unused
borrowing base to consolidated current liabilities of not less
than 1.0 to 1.0; and
|
|
|
|
maintain a ratio of total debt to EBITDA of not more than 2.5 to
1.0.
|
The Company is in compliance with the financial covenants under
the bank credit facility as of December 31, 2005.
As of December 31, 2005, $152.0 million was
outstanding under the bank credit facility, and the weighted
average interest rate was 7.15%. Net proceeds of approximately
$38 million generated by the private placement in March
2005 were used to repay existing bank debt.
As of December 31, 2004, $105.0 million was
outstanding under the bank credit facility, and the weighted
average interest rate was 5.20%. The borrowing base under the
bank credit facility is $135 million at December 31,
2004.
JEDI
Term Promissory Note
As part of the Merger consideration payable to JEDI, the Company
issued a term promissory note to JEDI in the amount of
$10 million. The note matured on March 2, 2006, and
bore interest, payable in kind at our option, at a rate of
10% per annum until March 2, 2005, and 12% per
annum thereafter unless paid in cash in which event the rate
remained 10% per annum. We chose to pay interest in cash
rather than in kind. The JEDI note was secured by a lien on
three of the Companys non-proven, non-producing properties
located in the Outer Continental Shelf of the Gulf of Mexico.
The Company could offset against the note the amount of certain
claims for indemnification that could be asserted against JEDI
under the terms of the merger agreement. The JEDI term
promissory note contained customary events of default, including
the occurrence of an event of default under the Companys
bank credit facility.
In March 2005, the Company repaid $6.0 million of the note
utilizing proceeds from the private placement in March 2005. The
$4.0 million balance remaining on the JEDI note at
December 31, 2005 was repaid in full on its maturity date
of March 2, 2006.
Cash
Interest Expense
Cash paid for interest was $6.1 million for 2005,
$5.4 million and -0- million for 2004 Post-Merger and 2004
Pre-Merger, respectively, and $4.0 million for 2003.
We have adopted an Equity Participation Plan that provided for
the one-time grant at the closing of our private equity
placement on March 11, 2005 of 2,267,270 restricted shares
of our common stock to certain of our employees. No further
grants will be made under the Equity Participation Plan,
although persons who receive such a grant will be eligible for
future awards of restricted stock or stock options under our
Amended and Restated Stock Incentive Plan described below. We
intended the grants of restricted stock under the Equity
Participation Plan to serve as a means of incentive compensation
for performance and not primarily as an opportunity to
participate in the equity appreciation of our common stock.
Therefore, Equity Participation Plan grantees did not pay any
consideration for the common stock they received, and we
received no remuneration
F-45
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
for the stock. Grantees are entitled to vote, and accrue
dividends on, the restricted stock prior to vesting; provided,
however that any dividends that accrue on the restricted stock
prior to vesting will only be paid to grantees to the extent the
restricted stock vests. In connection with the merger with
Forest Energy Resources, (i) the 463,656 shares of
restricted stock held by non-executive employees vested, and
(ii) each of Mariners executive officers agreed, in
exchange for a cash payment of $1,000, that his or her shares of
restricted stock will not vest before the later of
March 11, 2006 or ninety days after the effective date of
the merger, which is May 31, 2006.
We adopted a Stock Incentive Plan which became effective
March 11, 2005 and was amended and restated on
March 2, 2006. Awards to participants under the Amended and
Restated Stock Incentive Plan may be made in the form of
incentive stock options, or ISOs, non-qualified stock options or
restricted stock. The participants to whom awards are granted,
the type or types of awards granted to a participant, the number
of shares covered by each award, the purchase price, conditions
and other terms of each award are determined by the Board of
Directors or a committee thereof. A total of 6.5 million
shares of Mariners common stock is subject to the Amended
and Restated Stock Incentive Plan. No more than
2.85 million shares issuable upon exercise of options or as
restricted stock can be issued to any individual. As of
March 17, 2006, approximately 5.7 million shares
remained available under the Amended and Restated Stock
Incentive Plan for future issuance to participants. Unless
sooner terminated, no award may be granted under the Amended and
Restated Stock Incentive Plan after October 12, 2015.
For the two years ended December 31, 2004 and 2003, Mainer
Energy, Inc. had no outstanding stock options. During the year
ended December 31, 2005, we granted 2,267,270 shares
of restricted stock and options to purchase 809,000 shares
of stock. We also issued 3.6 million shares of common stock
in March 2005 in connection with our private placement offering.
The fair value of the restricted shares at date of grant has
been recorded in stockholders equity as unearned
compensation and is being amortized over the vesting period as
compensation expense. We recorded compensation expense of
$25.7 million in the year ended December 31, 2005
related to the restricted stock granted in 2005 and stock
options outstanding as of December 31, 2005. The weighted
average fair value of options granted during the year ended
December 31, 2005 was $2.69. For the year ended
December 31, 2004, we recorded no stock compensation
expense related to either restricted stock or stock options.
The following table is a summary of stock option activity for
the year ended and as of December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Outstanding at beginning of year
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
809,000
|
|
|
|
14.02
|
|
Exercised
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year
|
|
|
809,000
|
|
|
$
|
14.02
|
|
|
|
|
|
|
|
|
|
|
Outstanding exercisable at end of
year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for future grant as
options or restricted stock
|
|
|
1,191,000
|
|
|
|
|
|
F-46
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table summarizes certain information about stock
options outstanding at December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Number
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Number
|
|
|
Exercise
|
|
|
|
|
|
|
Outstanding
|
|
|
Life (Years)
|
|
|
Price
|
|
|
Exercisable
|
|
|
Price
|
|
|
|
|
|
$14.00-$17.00
|
|
|
809,000
|
|
|
|
9.2
|
|
|
$
|
14.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes shares of restricted stock
granted for the year ended December 31, 2005:
|
|
|
|
|
|
|
Restricted
|
|
|
|
Shares
|
|
|
Outstanding at beginning of year
|
|
|
|
|
Granted
|
|
|
2,267,270
|
|
Vested
|
|
|
|
|
Forfeited
|
|
|
|
|
Outstanding at end of year
|
|
|
2,267,270
|
|
Outstanding vested at end of year
|
|
|
|
|
Available for future grant under
Equity Participation Plan
|
|
|
|
|
Average Fair Value of
Shares Granted During Year
|
|
$
|
14.00
|
|
|
|
6.
|
Employee
Benefit And Royalty Plans
|
Employee Capital Accumulation Plan The
Company provides all full-time employees (who are at least
18 years of age) participation in the Employee Capital
Accumulation Plan (the Plan) which is comprised of a
contributory 401(k) savings plan and a discretionary profit
sharing plan. Under the 401(k) feature, the Company, at its sole
discretion, may contribute an employer-matching contribution
equal to a percentage not to exceed 50% of each eligible
participants matched salary reduction contribution as
defined by the Plan. Under the discretionary profit sharing
contribution feature of the Plan, the Companys
contribution, if any, must be determined annually and must be 4%
of the lesser of the Companys operating income or total
employee compensation and shall be allocated to each eligible
participant pro rata to his or her compensation. During the
years ended December 31, 2005, 2004 and 2003, the Company
contributed $240,650, $193,521 and $159,241, respectively, to
the Plan related to the discretionary feature. Currently there
are no plans to terminate the Plan.
Overriding Royalty Interests Pursuant to
agreements, certain employees and consultants of the Company are
entitled to receive, as incentive compensation, overriding
royalty interests (Overriding Royalty Interests) in
certain oil and gas prospects acquired by the Company. Such
Overriding Royalty Interests entitle the holder to receive a
specified percentage of the gross proceeds from the future sale
of oil and gas (less production taxes), if any, applicable to
the prospects. Cash payments made by the Company to current
employees and consultants with respect to Overriding Royalty
Interests were $2.6 million for 2005, $2.5 million and
$0.2 million for 2004 Post-Merger and 2004 Pre-Merger,
respectively, and $2.0 million for 2003.
F-47
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
|
|
7.
|
Commitments
And Contingencies
|
Minimum Future Lease Payments The Company
leases certain office facilities and other equipment under
long-term operating lease arrangements. Minimum rental
obligations under the Companys operating leases in effect
at December 31, 2005 are as follows (in thousands):
|
|
|
|
|
2006
|
|
$
|
1,161.4
|
|
2007
|
|
|
942.7
|
|
2008
|
|
|
941.0
|
|
2009
|
|
|
941.0
|
|
2010 and thereafter
|
|
|
3,448.1
|
|
Rental expense, before capitalization, was approximately
$509,000 for 2005, $486,000 and $78,000 for 2004 Post-Merger and
2004 Pre-Merger, respectively, and $569,000 for 2003.
Hedging Program The energy markets have
historically been very volatile, and there can be no assurance
that oil and gas prices will not be subject to wide fluctuations
in the future. In an effort to reduce the effects of the
volatility of the price of oil and natural gas on the
Companys operations, management has elected to hedge oil
and natural gas prices from time to time through the use of
commodity price swap agreements and costless collars. While the
use of these hedging arrangements limits the downside risk of
adverse price movements, it also limits future gains from
favorable movements.
As of December 31, 2005, the Company had the following
fixed price swaps outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2005 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2006
|
|
|
140,160
|
|
|
$
|
29.56
|
|
|
$
|
(4.7
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2006
|
|
|
1,827,547
|
|
|
|
5.53
|
|
|
|
(9.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(14.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005, the Company had the following
costless collars outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2006
|
|
|
251,850
|
|
|
$
|
32.65
|
|
|
$
|
41.52
|
|
|
$
|
(5.3
|
)
|
January 1
December 31, 2007
|
|
|
202,575
|
|
|
|
31.27
|
|
|
|
39.83
|
|
|
|
(4.7
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2006
|
|
|
7,347,450
|
|
|
|
5.78
|
|
|
|
7.85
|
|
|
|
(22.3
|
)
|
January 1
December 31, 2007
|
|
|
5,310,750
|
|
|
|
5.49
|
|
|
|
7.22
|
|
|
|
(16.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(49.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-48
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The Company has not entered into any hedge transactions
subsequent to December 31, 2005.
As of December 31, 2004, the Company had the following
fixed price swaps outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2005 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2005
|
|
|
606,000
|
|
|
$
|
26.15
|
|
|
$
|
(10.0
|
)
|
January 1
December 31, 2006
|
|
|
140,160
|
|
|
|
29.56
|
|
|
|
(1.5
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2005
|
|
|
8,670,159
|
|
|
|
5.41
|
|
|
|
(7.0
|
)
|
January 1
December 31, 2006
|
|
|
1,827,547
|
|
|
|
5.53
|
|
|
|
(1.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(20.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2004, the Company had the following
costless collars outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Gain/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2005
|
|
|
229,950
|
|
|
$
|
35.60
|
|
|
$
|
44.77
|
|
|
$
|
(0.4
|
)
|
January 1
December 31, 2006
|
|
|
251,850
|
|
|
|
32.65
|
|
|
|
41.52
|
|
|
|
(0.7
|
)
|
January 1
December 31, 2007
|
|
|
202,575
|
|
|
|
31.27
|
|
|
|
39.83
|
|
|
|
(0.6
|
)
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
December 31, 2005
|
|
|
2,847,000
|
|
|
|
5.73
|
|
|
|
7.80
|
|
|
|
0.4
|
|
January 1
December 31, 2006
|
|
|
3,514,950
|
|
|
|
5.37
|
|
|
|
7.35
|
|
|
|
(0.3
|
)
|
January 1
December 31, 2007
|
|
|
1,806,750
|
|
|
|
5.08
|
|
|
|
6.26
|
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company has reviewed the financial strength of its
counterparties and believes the credit risk associated with
these swaps and costless collars to be minimal.
F-49
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table sets forth the results of hedging
transactions during the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
2004
|
|
|
|
|
|
|
Year Ended
|
|
|
through
|
|
|
through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands except per share data)
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity hedged (MMbtu)
|
|
|
15,917,159
|
|
|
|
16,723,063
|
|
|
|
2,100,000
|
|
|
|
25,520,000
|
|
Increase (Decrease) in Natural Gas
Sales (in thousands)
|
|
$
|
(33,010
|
)
|
|
$
|
(12,223
|
)
|
|
$
|
1,431
|
|
|
$
|
(27,097
|
)
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity hedged (MBbls)
|
|
|
836
|
|
|
|
1,375
|
|
|
|
179
|
|
|
|
730
|
|
Increase (Decrease) in Crude Oil
Sales (in thousands)
|
|
$
|
(20,789
|
)
|
|
$
|
(16,221
|
)
|
|
$
|
(686
|
)
|
|
$
|
(4,969
|
)
|
The Companys hedge transactions resulted in a
$53.8 million loss for 2005 and a $28.4 million loss
for 2004 Post-Merger and a $0.7 million gain for 2004
Pre-Merger. $4.5 million of the 2005 loss and
$7.9 million of the Post-Merger loss relates to the hedge
liability recorded at the merger date. In addition, in 2003 the
Company recorded $3.2 million of expense related to the
settlement of derivatives that were not accounted for as hedges.
Other Commitments In the ordinary course of
business, the Company enters into long-term commitments to
purchase seismic data. The minimum annual payments under these
contracts are $14.5 and $6.5 million in 2006 and 2007,
respectively. In 2005, the Company entered into a joint
exploration agreement granting the joint venture partner the
right to participate in prospects covered by certain seismic
data licensed by the Company in return for $6.0 million in
scheduled payments to be received by the Company over a
two-year
period. Subsequent to December 31, 2005, the Company
entered into four additional long-term commitments to purchase
seismic data in the amount of $26.9 million.
Deepwater Rig In February 2000, the Company
and Noble Drilling Corporation entered into an agreement whereby
the Company committed to using a Noble deepwater rig for a
minimum of 660 days over a five-year period. The Company
assigned to Noble working interests in seven of the
Companys deepwater exploration prospects and agreed to pay
Nobles share of certain costs of drilling the initial test
well on the prospects. As of December 31, 2003, the Company
had no further obligation under the agreement for the use of the
rig and had drilled five of the seven prospects. Subsequent to
year end 2003, the Company and Noble Drilling Corporation agreed
to exchange Nobles interest in one of the two remaining
undrilled prospects for an interest in another prospect drilled
in the first quarter of 2004 and exchange Nobles carried
working interest in the other remaining undrilled prospect for a
larger un-carried working interest in the prospect, and the
Company agreed to use one of two Noble drilling rigs for an
aggregate of 75 days. Mariner has no further obligations
under this agreement.
MMS Appeal Mariner operates numerous
properties in the Gulf of Mexico. Two of such properties were
leased from the Mineral Management Service subject to the 1996
Royalty Relief Act. This Act relieved the obligation to pay
royalties on certain leases until a designated volume is
produced. These leases contained language that limited royalty
relief if commodity prices exceeded predetermined levels. For
the years 2000,
F-50
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
2001, 2003, 2004 and 2005, commodity prices exceeded the
predetermined levels. The Company believes the MMS did not have
the authority to set pricing limits in these leases and has
filed an administrative appeal with the MMS regarding this
matter and withheld payment of royalties on the leases. The
Company has recorded a liability for 100% of the exposure on
this matter which on December 31, 2005 was
$16.0 million. In April 2005, the MMS denied the
administrative appeal. On October 3, 2005, we filed suit in
the U.S. District Court for the Southern District of Texas
seeking judicial review of the dismissal of our appeal by the
Board of Land Appeals.
Insurance Matters In September 2004, the
Company incurred damage from Hurricane Ivan that affected its
Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields.
Production from Mississippi Canyon 357 was shut-in until March
2005, when necessary repairs were completed and production
recommenced. Production from Ochre is currently shut-in awaiting
rerouting of umbilical and flow lines to another host platform.
Prior to Hurricane Ivan, this field was producing at a net rate
of approximately 6.5 MMcfe per day. Production from Ochre
is expected to recommence in the second quarter of 2006. In
addition, a semi-submersible rig on location at the
Companys Viosca Knoll 917 (Swordfish) field was blown off
location by the hurricane and incurred damage. Until we are able
to complete all the repair work and submit costs to the
insurance underwriters for review, the full extent of our
insurance recovery and the resulting net cost to the Company is
unknown. We expect the net cost to the Company to be at least
equal to the amount of our annual deductible of
$1.25 million plus the single occurrence deductible of
$.375 million.
In August 2005 and September 2005, Mariner incurred damage from
Hurricanes Katrina and Rita that affected several of its
offshore fields. Hurricane Katrina caused minor damage to our
owned platforms and facilities. Production that was shut-in by
the hurricane was recommenced within three weeks of the
hurricane, with the exception of two minor non-operated fields.
However, Hurricane Katrina inflicted damage to host facilities
for our Pluto, Rigel and Ochre projects that is expected to
delay
start-up of
these projects until the second quarter of 2006 for Pluto and
Ochre. Rigel production began in the first quarter of 2006.
Hurricane Rita caused minor damage to our owned platforms and
some damage to certain host facilities of our development
projects. Production shut-in as a result of Hurricane Rita fully
recommenced within three weeks of the hurricane, with the
exception of one minor field. We cannot estimate a range of loss
arising from the hurricanes until we are able to more completely
assess the impacts on our properties and the properties of our
operational partners. Until we are able to complete all the
repair work and submit costs to our insurance underwriters for
review, the full extent of our insurance recovery and the
resulting net cost to us for Hurricanes Katrina and Rita will be
unknown. For the insurance period ending September 30,
2005, we carried a $3.0 million annual deductible and a
$.375 million single occurrence deductible.
Effective March 2, 2006, Mariner has been accepted as a
member of OIL Insurance, Ltd., or OIL, an industry insurance
cooperative, through which the assets of both Mariner and the
Forest Gulf of Mexico operations are insured. The coverage
contains a $5 million annual per occurrence deductible for
the combined assets and a $250 million per occurrence loss
limit. However, if a single event causes losses to OIL insured
assets in excess of $1 billion in the aggregate (effective
June 1, 2006, such amount will be reduced to
$500 million), amounts covered for such losses will be
reduced on a pro rata basis among OIL members. Pending review of
our insurance program, we have maintained our commercially
underwritten insurance coverage for the pre-merger Mariner
assets which expires on September 30, 2006. This coverage
contains a 3 million annual deductible and a $500,000
occurrence deductible, $150 million of aggregate loss
limits, and limited business interruption coverage. While the
coverage remains in effect, it will be primary to the OIL
coverage for the pre-merger Mariner assets.
F-51
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Litigation The Company, in the ordinary
course of business, is a claimant
and/or a
defendant in various legal proceedings, including proceedings as
to which the Company has insurance coverage. The Company does
not consider its exposure in these proceedings, individually and
in the aggregate, to be material.
The components of the federal income tax provision are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
2004
|
|
|
|
|
|
|
Year Ended
|
|
|
through
|
|
|
through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
|
(In thousands)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
21,294
|
|
|
|
28,783
|
|
|
|
8,072
|
|
|
|
10,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21,294
|
|
|
|
28,783
|
|
|
|
8,072
|
|
|
|
10,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation of the statutory
federal income tax with the income tax provision (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3, 2004
|
|
|
January 1
|
|
|
|
|
|
|
|
|
|
Year Ending
|
|
|
through
|
|
|
through
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
$
|
|
|
%
|
|
|
$
|
|
|
%
|
|
|
$
|
|
|
%
|
|
|
$
|
|
|
%
|
|
|
|
(In thousands, except percentages)
|
|
|
Income before income taxes
including change in accounting in 2003
|
|
|
61,775
|
|
|
|
|
|
|
|
82,402
|
|
|
|
|
|
|
|
22,898
|
|
|
|
|
|
|
|
48,676
|
|
|
|
|
|
Income tax expense (benefit)
computed at statutory rates
|
|
|
21,621
|
|
|
|
35
|
|
|
|
28,841
|
|
|
|
35
|
|
|
|
8,014
|
|
|
|
35
|
|
|
|
17,037
|
|
|
|
35
|
|
Change in valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,090
|
)
|
|
|
(14
|
)
|
Other
|
|
|
(327
|
)
|
|
|
(1
|
)
|
|
|
(58
|
)
|
|
|
|
|
|
|
58
|
|
|
|
|
|
|
|
485
|
|
|
|
|
|
Tax Expense
|
|
|
21,294
|
|
|
|
34
|
|
|
|
28,783
|
|
|
|
35
|
|
|
|
8,072
|
|
|
|
35
|
|
|
|
10,432
|
|
|
|
21
|
|
Federal income taxes of $1.6 million were paid by the
Company for the 2004 Post-Merger period for alternative minimum
tax liability, and no federal income taxes were paid by the
Company in the years ended December 31, 2003 and 2005. An
income tax benefit of $1,045,000 was included as a reduction in
Change in Accounting Principle for the adoption of
SFAS No. 143 in 2003.
F-52
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The Companys deferred tax position reflects the net tax
effects of the temporary differences between the carrying
amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax reporting.
Significant components of the deferred tax assets and
liabilities are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Net operating loss carry forwards
|
|
$
|
45,171
|
|
|
$
|
15,639
|
|
Alternative minimum Tax Credit
|
|
|
1,606
|
|
|
|
1,606
|
|
Differences between book and tax
basis of receivables
|
|
|
|
|
|
|
|
|
Other comprehensive
income-derivative instruments
|
|
|
22,332
|
|
|
|
6,262
|
|
Employee stock compensation
|
|
|
9,004
|
|
|
|
|
|
Valuation allowance
|
|
|
(5,909
|
)
|
|
|
(5,909
|
)
|
Other
|
|
|
671
|
|
|
|
|
|
Total net deferred tax assets
|
|
|
72,875
|
|
|
|
17,598
|
|
Deferred Tax
Liabilities:
|
|
|
|
|
|
|
|
|
Differences between book and tax
basis of properties
|
|
|
(72,744
|
)
|
|
|
(14,569
|
)
|
|
|
|
|
|
|
|
|
|
Total net deferred asset
(liability)
|
|
|
131
|
|
|
$
|
3,029
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2005, the Company had federal and state net
operating loss carryforwards of approximately $129,059 and
$7,055 respectively, which will expire in varying amounts
between 2018 and 2025 and are subject to certain limitations on
an annual basis. A valuation allowance has been established
against net operating losses where it is more likely than not
that such losses will expire before they are utilized.
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources (the Forest Transaction). Prior to the
consummation of the merger, Forest transferred and contributed
the assets and certain liabilities associated with its offshore
Gulf of Mexico operations to Forest Energy Resources.
Immediately prior to the merger, Forest distributed all of the
outstanding shares of Forest Energy Resources to Forest
shareholders on a pro rata basis. Forest Energy Resources then
merged with a newly formed subsidiary of Mariner, and became a
new wholly owned subsidiary of Mariner. Immediately following
the merger, approximately 59% of the Mariner common stock was
held by shareholders of Forest and approximately 41% of Mariner
common stock was held by the pre-merger stockholders of Mariner.
In the merger Mariner issued 50,637,010 shares of common
stock to Forest shareholders.
The sources and uses of funds related to the Forest Transaction
were as follows:
|
|
|
|
|
Mariner Energy, Inc. bank loan
proceeds
|
|
$
|
180.2
|
|
Refinancing of assumed debt
|
|
$
|
176.2
|
|
Acquisition costs and other
expenses
|
|
|
4.0
|
|
Total
|
|
$
|
180.2
|
|
F-53
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
In addition, approximately $3.8 million in merger-related
costs were funded from bank loan proceeds prior to the closing
of the transaction.
Mariner Energy, Inc. is the acquiring entity in accordance with
the provisions of Statement of Financial Accounting Standards
No. 141, Business Combinations
(SFAS 141). As a results, the assets and
liabilities acquired by Mariner in the Forest Transaction will
be adjusted to their estimated fair values as of the effective
date of the transaction (March 2, 2006).
The initial fair value estimate of the underlying assets and
liabilities acquired is determined by estimating the value of
the underlying proved reserves at the transaction date plus or
minus the fair value of other assets and liabilities, including
inventory, unproved oil and gas properties, gas imbalances, debt
(at face value), derivatives, and abandonment liabilities. The
final purchase price allocation will be determined after closing
based on the actual fair value of current assets, current
liabilities, indebtedness, long-term liabilities, proven and
unproved oil and gas properties and identifiable intangible
assets. We are continuing to evaluate all of these items;
accordingly, the final purchase price may differ in material
respects from that presented below. Carryover basis accounting
applies for tax purposes. The following table summarizes the
estimated fair values of the assets acquired and liabilities
assumed at the March 2, 2006 transaction date:
|
|
|
|
|
|
|
(In millions)
|
|
|
Oil and natural gas properties
|
|
$
|
1,617.0
|
|
Other assets
|
|
|
14.5
|
|
Abandonment liabilities
|
|
|
(148.0
|
)
|
Long-term debt
|
|
|
(176.2
|
)
|
Fair value of oil and natural gas
derivatives
|
|
|
(17.5
|
)
|
Deferred tax liability(1)
|
|
|
(397.6
|
)
|
Total
|
|
$
|
892.2
|
|
|
|
|
(1) |
|
Represents deferred income taxes recorded at the date of the
transaction due to differences between the book basis and the
tax basis of assets. For book purposes, the assets of the Forest
Gulf of Mexico operations had a
step-up in
basis while the existing tax basis carried over. |
On March 2, 2006, Mariner and Mariner Energy Resources,
Inc. entered into a $500 million senior secured revolving
credit facility, and an additional $40 million senior
secured letter of credit facility. The revolving credit facility
will mature on March 2, 2010, and the $40 million
letter of credit facility will mature on March 2, 2009.
Mariner used borrowings under the revolving credit facility to
facilitate the merger and to retire existing debt, and we may
use borrowings in the future for general corporate purposes. The
$40 million letter of credit facility has been used to
obtain a letter of credit in favor of Forest to secure
Mariners performance of its obligations under an existing
drill-to-earn
program. The outstanding principal balance of loans under the
revolving credit facility may not exceed the borrowing base,
which initially has been set at $400 million. If the
borrowing base falls below the outstanding balance under the
revolving credit facility, Mariner will be required to prepay
the deficit, pledge additional unencumbered collateral, repay
the deficit and cash collateralize certain letters of credit, or
effect some combination of such prepayment, pledge and repayment
and collateralization.
As part of the Merger consideration payable to JEDI, the Company
issued a term promissory note to JEDI in the amount of
$10 million. The note matured on March 2, 2006, and
bore interest, payable in kind at our option, at a rate of
10% per annum until March 2, 2005, and 12% per
annum thereafter unless paid in
F-54
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
cash in which event the rate remained 10% per annum. In
March 2005, the Company repaid $6.0 million of the note
utilizing proceeds from the private placement in March 2005. The
$4.0 million balance remaining on the JEDI note at
December 31, 2005 was repaid in full on its maturity date
of March 2, 2006.
Effective March 2, 2006, Mariner has been accepted as a
member of OIL, an industry insurance cooperative, through which
the assets of both Mariner and the Forest Gulf of Mexico
operations are insured. The coverage contains a $5 million
annual per occurrence deductible for the combined assets and a
$250 million per occurrence loss limit. However, if a
single event causes losses to OIL insured assets in excess of
$1 billion in the aggregate (effective June 1, 2006,
such amount will be reduced to $500 million), amounts
covered for such losses will be reduced on a pro rata basis
among OIL members. Pending review of its insurance program, the
Company has maintained our commercially underwritten insurance
coverage for the pre-merger Mariner assets which expires on
September 30, 2006. This coverage contains a
$3 million annual deductible and a $500,000 occurrence
deductible, $150 million of aggregate loss limits, and
limited business interruption coverage. While the coverage
remains in effect, it will be primary to the OIL coverage for
the pre-merger Mariner assets.
The Company has adopted an Equity Participation Plan that
provided for the one-time grant at the closing of our private
equity placement on March 11, 2005 of 2,267,270 restricted
shares of our common stock to certain of our employees. In
connection with the merger with Forest Energy Resources on
March 2, 2006, (i) the 463,656 shares of
restricted stock held by non-executive employees vested, and
(ii) each of Mariners executive officers agreed, in
exchange for a cash payment of $1,000, that his or her shares of
restricted stock will not vest before the later of
March 11, 2006 or ninety days after the effective date of
the merger, which is May 31, 2006.
The Company adopted a Stock Incentive Plan which became
effective March 11, 2005 and was amended and restated on
March 2, 2006. A total of 6.5 million shares of
Mariners common stock is subject to the Amended and
Restated Stock Incentive Plan. No more than 2.85 million
shares issuable upon exercise of options or as restricted stock
can be issued to any individual. As of March 17, 2006,
approximately 5.7 million shares remained available under
the Amended and Restated Stock Incentive Plan for future
issuance to participants. Unless sooner terminated, no award may
be granted under the Amended and Restated Stock Incentive Plan
after October 12, 2015.
|
|
10.
|
Oil and
Gas Producing Activities and Capitalized Costs
(Unaudited)
|
The results of operations from the Companys oil and gas
producing activities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Oil and gas sales
|
|
$
|
196,122
|
|
|
$
|
214,187
|
|
|
$
|
142,543
|
|
Lease operating costs
|
|
|
(29,882
|
)
|
|
|
(25,484
|
)
|
|
|
(24,719
|
)
|
Transportation
|
|
|
(2,336
|
)
|
|
|
(3,029
|
)
|
|
|
(6,252
|
)
|
Depreciation, depletion and
amortization
|
|
|
(59,426
|
)
|
|
|
(64,911
|
)
|
|
|
(48,339
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
104,478
|
|
|
$
|
120,763
|
|
|
$
|
63,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-55
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table summarizes the Companys capitalized
costs of oil and gas properties.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Unevaluated properties, not
subject to amortization
|
|
$
|
40,176
|
|
|
$
|
36,245
|
|
|
$
|
36,619
|
|
Properties subject to amortization
|
|
|
574,725
|
|
|
|
319,553
|
|
|
|
599,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized costs
|
|
|
614,901
|
|
|
|
355,798
|
|
|
|
636,381
|
|
Accumulated depreciation,
depletion and amortization
|
|
|
(109,183
|
)
|
|
|
(52,680
|
)
|
|
|
(429,323
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
505,718
|
|
|
$
|
303,118
|
|
|
$
|
207,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred in property acquisition, exploration and
development activities were as follows (in thousands, except per
equivalent mcf amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
12,366
|
|
|
$
|
4,844
|
|
|
$
|
4,746
|
|
Proved properties
|
|
|
52,503
|
|
|
|
4,863
|
|
|
|
|
|
Exploration costs
|
|
|
50,049
|
|
|
|
43,022
|
|
|
|
26,823
|
|
Development costs
|
|
|
121,685
|
|
|
|
88,626
|
|
|
|
44,299
|
|
Capitalized internal costs
|
|
|
6,016
|
|
|
|
7,334
|
|
|
|
7,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
242,619
|
|
|
$
|
148,689
|
|
|
$
|
83,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization rate per equivalent Mcf
|
|
$
|
2.04
|
|
|
$
|
1.73
|
|
|
$
|
1.45
|
|
The Company capitalizes internal costs associated with
exploration activities in progress. These capitalized costs were
approximately 35%, 46% and 48% of the Companys gross
general and administrative expenses, excluding stock
compensation expense for the years ended December 31, 2005,
2004 and 2003, respectively.
The following table summarizes costs related to unevaluated
properties that have been excluded from amounts subject to
amortization at December 31, 2005. Three relatively
significant projects were included in unproved properties with
balances of $6.0 million, $5.8 million and
$5.5 million at December 31, 2005. These projects are
expected to be evaluated within the next twelve months. The
Company regularly evaluates these
F-56
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
costs to determine whether impairment has occurred. The majority
of these costs are expected to be evaluated and included in the
amortization base within three years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period Incurred
|
|
|
Total at
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Prior
|
|
|
2005
|
|
|
Unproved leasehold acquisition and
geological and geophysical costs
|
|
$
|
15,735
|
|
|
$
|
2,455
|
|
|
$
|
2,741
|
|
|
$
|
3,428
|
|
|
|
24,359
|
|
Unevaluated exploration and
development costs
|
|
|
14,975
|
|
|
|
173
|
|
|
|
|
|
|
|
|
|
|
|
15,148
|
|
Capitalized interest
|
|
|
450
|
|
|
|
123
|
|
|
|
96
|
|
|
|
|
|
|
|
669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
31,160
|
|
|
$
|
2,751
|
|
|
$
|
2,837
|
|
|
$
|
3,428
|
|
|
$
|
40,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the excluded costs at December 31, 2005 relate to
activities in the Gulf of Mexico.
|
|
11.
|
Supplemental
Oil and Gas Reserve and Standardized Measure Information
(Unaudited)
|
Estimated proved net recoverable reserves as shown below include
only those quantities that are expected to be commercially
recoverable at prices and costs in effect at the balance sheet
dates under existing regulatory practices and with conventional
equipment and operating methods. Proved developed reserves
represent only those reserves expected to be recovered through
existing wells. Proved undeveloped reserves include those
reserves expected to be recovered from new wells on undrilled
acreage or from existing wells on which a relatively major
expenditure is required for recompletion. Also included in the
Companys proved undeveloped reserves as of
December 31, 2005 were reserves expected to be recovered
from wells for which certain drilling and completion operations
had occurred as of that date, but for which significant future
capital expenditures were required to bring the wells into
commercial production.
Reserve estimates are inherently imprecise and may change as
additional information becomes available. Furthermore, estimates
of oil and gas reserves, of necessity, are projections based on
engineering data, and there are uncertainties inherent in the
interpretation of such data as well as in the projection of
future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of
estimating underground accumulations of oil and natural gas that
cannot be measured exactly, and the accuracy of any reserve
estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.
Accordingly, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular
group of properties, classifications of such reserves based on
risk of recovery and estimates of the future net cash flows
expected therefrom prepared by different engineers or by the
same engineers at different times may vary substantially. There
also can be no assurance that the reserves set forth herein will
ultimately be produced or that the proved undeveloped reserves
set forth herein will be developed within the periods
anticipated. It is likely that variances from the estimates will
be material. In addition, the estimates of future net revenues
from proved reserves of the Company and the present value
thereof are based upon certain assumptions about future
production levels, prices and costs that may not be correct when
judged against actual subsequent experience. The Company
emphasizes with respect to the estimates prepared by independent
petroleum engineers that the discounted future net cash flows
should not be construed as representative of the fair market
value of the proved reserves owned by the Company since
discounted future net cash flows are based upon projected cash
flows which do not provide for changes in oil and natural gas
prices from those in effect on the date indicated or for
escalation of expenses and capital costs subsequent to such
date.
F-57
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The meaningfulness of such estimates is highly dependent upon
the accuracy of the assumptions upon which they are based.
Actual results will differ, and are likely to differ materially,
from the results estimated.
ESTIMATED
QUANTITIES OF PROVED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
|
Oil (Mbbl)
|
|
|
(MMcf)
|
|
|
Equivalent (MMcfe)
|
|
|
December 31,
2002
|
|
|
11,018
|
|
|
|
136,055
|
|
|
|
202,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
900
|
|
|
|
(3,076
|
)
|
|
|
2,324
|
|
Extensions, discoveries and other
additions
|
|
|
2,795
|
|
|
|
62,609
|
|
|
|
79,379
|
|
Sale of reserves in place
|
|
|
(34
|
)
|
|
|
(44,233
|
)
|
|
|
(44,437
|
)
|
Production
|
|
|
(1,600
|
)
|
|
|
(23,771
|
)
|
|
|
(33,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2003
|
|
|
13,079
|
|
|
|
127,584
|
|
|
|
206,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
1,249
|
|
|
|
19,797
|
|
|
|
27,291
|
|
Extensions, discoveries and other
additions
|
|
|
2,225
|
|
|
|
28,334
|
|
|
|
41,684
|
|
Sale of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(2,298
|
)
|
|
|
(23,782
|
)
|
|
|
(37,570
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2004
|
|
|
14,255
|
|
|
|
151,933
|
|
|
|
237,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
835
|
|
|
|
963
|
|
|
|
5,971
|
|
Extensions, discoveries and other
additions
|
|
|
1,167
|
|
|
|
22,307
|
|
|
|
29,309
|
|
Purchases of reserves in place
|
|
|
7,181
|
|
|
|
50,837
|
|
|
|
93,923
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(1,791
|
)
|
|
|
(18,354
|
)
|
|
|
(29,100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2005
|
|
|
21,647
|
|
|
|
207,686
|
|
|
|
337,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ESTIMATED
QUANTITIES OF PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
|
Oil (Mbbl)
|
|
|
(MMcf)
|
|
|
Equivalent (MMcfe)
|
|
|
December 31, 2002
|
|
|
3,609
|
|
|
|
64,586
|
|
|
|
86,240
|
|
December 31, 2003
|
|
|
5,951
|
|
|
|
60,881
|
|
|
|
96,587
|
|
December 31, 2004
|
|
|
6,339
|
|
|
|
71,361
|
|
|
|
109,395
|
|
December 31, 2005
|
|
|
9,564
|
|
|
|
110,011
|
|
|
|
167,395
|
|
F-58
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following is a summary of a Standardized Measure of
discounted net future cash flows related to the Companys
proved oil and gas reserves. The information presented is based
on a calculation of proved reserves using discounted cash flows
based on year-end prices, costs and economic conditions and a
10% discount rate. The additions to proved reserves from new
discoveries and extensions could vary significantly from year to
year. Additionally, the impact of changes to reflect current
prices and costs of reserves proved in prior years could also be
significant. Accordingly, the information presented below should
not be viewed as an estimate of the fair value of the
Companys oil and gas properties, nor should it be
considered indicative of any trends.
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Future cash inflows
|
|
$
|
3,451,321
|
|
|
$
|
1,601,240
|
|
|
$
|
1,182,509
|
|
Future production costs
|
|
|
(687,583
|
)
|
|
|
(308,190
|
)
|
|
|
(196,695
|
)
|
Future development costs
|
|
|
(386,497
|
)
|
|
|
(193,689
|
)
|
|
|
(138,694
|
)
|
Future income taxes
|
|
|
(695,921
|
)
|
|
|
(285,701
|
)
|
|
|
(183,199
|
)
|
Future net cash flows
|
|
|
1,681,320
|
|
|
|
813,660
|
|
|
|
663,921
|
|
Discount of future net cash flows
at 10% per annum
|
|
|
(774,755
|
)
|
|
|
(319,278
|
)
|
|
|
(245,762
|
)
|
Standardized measure of discounted
future net cash flows
|
|
$
|
906,565
|
|
|
$
|
494,382
|
|
|
$
|
418,159
|
|
During recent years, there have been significant fluctuations in
the prices paid for crude oil in the world markets and in the
United States, including the posted prices paid by purchasers of
the Companys crude oil. The NYMEX prices of oil and gas at
December 31, 2005, 2004 and 2003, used in the above table,
were $61.04, $43.45 and $32.52 per Bbl, respectively, and
$10.05, $6.15 and $5.96 per Mmbtu, respectively, and do not
include the effect of hedging contracts in place at period end.
F-59
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following are the principal sources of change in the
Standardized Measure of discounted future net cash flows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Sales and transfers of oil and gas
produced, net of production costs
|
|
$
|
(213,189
|
)
|
|
$
|
(185,673
|
)
|
|
$
|
(111,572
|
)
|
Net changes in prices and
production costs
|
|
|
425,317
|
|
|
|
27,767
|
|
|
|
27,403
|
|
Extensions and discoveries, net of
future development and production costs
|
|
|
119,501
|
|
|
|
88,167
|
|
|
|
180,237
|
|
Purchases of reserves in place
|
|
|
189,782
|
|
|
|
14,738
|
|
|
|
|
|
Development costs during period
and net change in development costs
|
|
|
46,632
|
|
|
|
44,417
|
|
|
|
31,709
|
|
Revision of previous quantity
estimates
|
|
|
16,323
|
|
|
|
89,814
|
|
|
|
6,276
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
(138,016
|
)
|
Net change in income taxes
|
|
|
(201,647
|
)
|
|
|
(27,634
|
)
|
|
|
(63,962
|
)
|
Accretion of discount before
income taxes
|
|
|
49,438
|
|
|
|
41,816
|
|
|
|
51,500
|
|
Changes in production rates
(timing) and other
|
|
|
(19,974
|
)
|
|
|
(17,189
|
)
|
|
|
(28,988
|
)
|
Net change
|
|
$
|
412,183
|
|
|
$
|
76,223
|
|
|
$
|
(45,413
|
)
|
|
|
12.
|
Unaudited
Quarterly Financial Information
|
The following table presents Mariners unaudited quarterly
financial information for 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
2004
|
|
|
|
2005 Quarter Ended
|
|
|
2004 Quarter Ended
|
|
|
through
|
|
|
through
|
|
|
|
December
|
|
|
September
|
|
|
June
|
|
|
March
|
|
|
December
|
|
|
September
|
|
|
June
|
|
|
March 31,
|
|
|
March 2,
|
|
|
|
31
|
|
|
30
|
|
|
30
|
|
|
31
|
|
|
31
|
|
|
30
|
|
|
30
|
|
|
2004
|
|
|
2004
|
|
|
Total revenues
|
|
$
|
48,465
|
|
|
$
|
43,662
|
|
|
$
|
51,776
|
|
|
$
|
55,807
|
|
|
$
|
51,897
|
|
|
$
|
50,202
|
|
|
$
|
51,086
|
|
|
$
|
21,238
|
|
|
$
|
39,764
|
|
Operating income
|
|
$
|
10,471
|
|
|
$
|
12,263
|
|
|
$
|
18,070
|
|
|
$
|
28,364
|
|
|
$
|
29,108
|
|
|
$
|
24,403
|
|
|
$
|
25,045
|
|
|
$
|
9,666
|
|
|
$
|
22,812
|
|
Income before income taxes
|
|
$
|
7,798
|
|
|
$
|
10,549
|
|
|
$
|
16,382
|
|
|
$
|
27,046
|
|
|
$
|
27,501
|
|
|
$
|
22,804
|
|
|
$
|
23,071
|
|
|
$
|
9,026
|
|
|
$
|
22,898
|
|
Provision for income taxes
|
|
|
2,880
|
|
|
|
3,606
|
|
|
|
5,537
|
|
|
|
9,271
|
|
|
|
9,562
|
|
|
|
8,498
|
|
|
|
7,630
|
|
|
|
3,093
|
|
|
|
8,072
|
|
Net income
|
|
$
|
4,918
|
|
|
$
|
6,943
|
|
|
$
|
10,845
|
|
|
$
|
17,775
|
|
|
$
|
17,939
|
|
|
$
|
14,306
|
|
|
$
|
15,441
|
|
|
$
|
5,933
|
|
|
$
|
14,826
|
|
Earnings per share:(1) Net income
per share basic
|
|
$
|
0.15
|
|
|
$
|
0.21
|
|
|
$
|
0.33
|
|
|
$
|
0.58
|
|
|
$
|
0.60
|
|
|
$
|
0.48
|
|
|
$
|
0.52
|
|
|
$
|
0.20
|
|
|
$
|
0.50
|
|
Net income per share
diluted
|
|
$
|
0.14
|
|
|
$
|
0.20
|
|
|
$
|
0.32
|
|
|
$
|
0.58
|
|
|
$
|
0.60
|
|
|
$
|
0.48
|
|
|
$
|
0.52
|
|
|
$
|
0.20
|
|
|
$
|
0.50
|
|
Weighted average shares
outstanding basic(2)
|
|
|
33,348,130
|
|
|
|
33,348,130
|
|
|
|
33,348,130
|
|
|
|
30,558,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
Weighted average shares
outstanding diluted
|
|
|
35,189,290
|
|
|
|
34,806,842
|
|
|
|
33,822,079
|
|
|
|
30,599,152
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
|
|
29,748,130
|
|
F-60
MARINER
ENERGY, INC.
NOTES TO
THE FINANCIAL STATEMENTS (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through
December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through
March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
|
|
|
(1) |
|
The sum of quarterly net income per share may not agree with
total year net income per share, as each quarterly computation
is based on the weighted average shares outstanding. |
|
(2) |
|
Restated for the 1,380 to 29,748,130 stock split, effective
March 3, 2005. |
|
|
13.
|
Supplemental
Guarantor Information
|
On April 24, 2006, the Company sold and issued to eligible
purchasers $300 million aggregate principal amount of its
71/2% senior
notes due 2013. The Notes are jointly and severally guaranteed
on a senior unsecured basis by the Companys existing and
future domestic subsidiaries (Subsidiary
Guarantors). In the future, the guarantees may be released
or terminated under certain circumstances. Each subsidiary
guarantee ranks senior in right of payment to any future
subordinated indebtedness of the guarantor subsidiary, ranks
equally in right of payment to all existing and future senior
unsecured indebtedness of the guarantor subsidiary and
effectively subordinate to all existing and future secured
indebtedness of the guarantor subsidiary, including its
guarantees of indebtedness under the Companys credit
facility, to the extent of the collateral securing such
indebtedness.
Guarantors Mariner LP, LLC and Mariner Energy Texas LP were
formed on December 29, 2004, did not commence operations
prior to January 1, 2005 and did not have material
operations in 2005. The net equity of these guarantors was $0 as
of December 31, 2005 and 2004, therefore, condensed
consolidating statements of operations, condensed consolidating
balance sheets and condensed consolidating statement of cash
flows is not presented.
F-61
Report of
Independent Registered Public Accounting Firm
The Board of Directors
Forest Oil Corporation:
We have audited the statements of revenues and direct operating
expenses of the Forest Gulf of Mexico operations (as defined in
note 1) for each of the years in the three-year period
ended December 31, 2005 (Historical Statements). These
Historical Statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the Historical Statements are
free of material misstatement. Our audits include consideration
of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the Historical Statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall presentation of the Historical Statements. We
believe that our audits provide a reasonable basis for our
opinion.
The accompanying statements were prepared for purposes of
complying with the rules and regulations of the Securities and
Exchange Commission and for inclusion in the registration
statement on
Form S-4
of Mariner Energy, Inc. The presentation is not intended to be a
complete presentation of the revenues and expenses of the Forest
Gulf of Mexico operations.
In our opinion, the Historical Statements referred to above
present fairly, in all material respects, the revenues and
direct operating expenses described in note 1 of the Forest
Gulf of Mexico operations for each of the years in the
three-year period ended December 31, 2005 in conformity
with accounting principles generally accepted in the United
States of America.
Denver, Colorado
March 27, 2006
F-62
FOREST
GULF OF MEXICO OPERATIONS
STATEMENTS
OF REVENUES AND DIRECT OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Oil and natural gas revenues
|
|
$
|
392,272
|
|
|
$
|
453,139
|
|
|
$
|
342,019
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
78,524
|
|
|
|
80,079
|
|
|
|
45,716
|
|
Transportation
|
|
|
3,383
|
|
|
|
2,175
|
|
|
|
2,652
|
|
Production taxes
|
|
|
2,215
|
|
|
|
1,548
|
|
|
|
1,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total direct operating expenses
|
|
|
84,122
|
|
|
|
83,802
|
|
|
|
49,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues in excess of direct
operating expenses
|
|
$
|
308,150
|
|
|
$
|
369,337
|
|
|
$
|
292,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to statements of revenues and direct
operating expenses.
F-63
FOREST
GULF OF MEXICO OPERATIONS
For the Years Ended December 31, 2005, 2004 and
2003
The accompanying historical statements of revenues and direct
operating expenses (the historical statements) are
presented using accrual basis, and represent the revenues and
direct operating expenses attributable to Forest Oil
Corporations (Forest Oil) interests in certain
producing oil and gas properties located offshore in the Gulf of
Mexico (the Forest Gulf of Mexico operations). The
historical statements were prepared from the historical
accounting records of Forest Oil. The historical statements
include only oil and natural gas revenues and direct lease
operating and production expenses, including transportation and
production taxes. The historical statements do not include
Federal and state income taxes, interest expenses, depletion,
depreciation and amortization, accretion, or general and
administrative expenses. Oil and gas revenues include gains or
losses on derivative instruments designated as hedges of oil and
gas production from these properties.
Complete financial statements, including a balance sheet, are
not presented as the oil and gas properties were not operated as
a separate business unit within Forest Oil. Accordingly, it is
not practicable to identify all assets and liabilities, or the
indirect operating costs applicable to these oil and gas
properties. As such, the historical statements of oil and gas
revenues and direct operating expenses have been presented in
lieu of the financial statements prescribed by
Rule 3-05
of Securities and Exchange Commission
Regulation S-X.
|
|
2.
|
DERIVATIVE
INSTRUMENTS
|
In order to reduce the impact of fluctuations in oil and gas
prices, or to protect the economics of property acquisitions,
from time to time Forest Oil entered into derivative instruments
designed to hedge future production from its oil and gas
properties, including future production from the properties
constituting the Forest Gulf of Mexico operations. Forest Oil
entered into derivative instruments, including commodity swaps,
collars, and other financial instruments with counterparties
who, in general, are participants in Forest Oils credit
facilities. These arrangements, which are based on prices
available in the financial markets at the time the contracts are
entered into, are settled in cash and do not require physical
deliveries.
The following table sets forth information regarding the
commodity swap agreements that will be transferred to Forest
Energy Resources, Inc. in the spin-off. The fair value of the
commodity swaps based on the futures prices quoted on
December 31, 2005 was a liability of approximately
$66.0 million.
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (NYMEX HH)
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Bbtu per
|
|
|
Hedged Price per
|
|
|
|
Day
|
|
|
MMBtu
|
|
|
First Quarter 2006
|
|
|
40.0
|
|
|
$
|
6.15
|
|
Second Quarter 2006
|
|
|
40.0
|
|
|
|
6.15
|
|
Third Quarter 2006
|
|
|
40.0
|
|
|
|
6.15
|
|
Fourth Quarter 2006
|
|
|
40.0
|
|
|
|
6.15
|
|
Net losses related to hedging activities of $128.2 million,
$57.1 million and $40.9 million were recognized for
the years ended December 31, 2005, 2004 and 2003,
respectively. Gains and losses recognized on hedging activities
are included in oil and natural gas revenues in the statements
of revenues and direct operating expenses.
F-64
FOREST
GULF OF MEXICO OPERATIONS
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES (Continued)
For the Years Ended December 31, 2005, 2004 and 2003
|
|
3.
|
SUPPLEMENTAL
INFORMATION REGARDING PROVED OIL AND GAS RESERVES
(UNAUDITED)
|
Supplemental oil and natural gas reserve information related to
the Forest Gulf of Mexico operations is presented in accordance
with the requirements of Statement of Financial Accounting
Standards No. 69, Disclosures about Oil and Gas
Producing Activities (FAS 69). There are
numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production
and timing of development expenditures.
Estimated
Proved Reserves
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids that geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions; i.e., prices and costs as of
the date the estimate is made.
Prices include consideration of changes in existing prices
provided only by contractual arrangement, but not on escalations
based on future conditions. Purchases of reserves in place
represent volumes recorded on the closing dates of the
acquisitions for financial accounting purposes.
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as
proved developed reserves only after testing by a
pilot project or after the operation of an installed program has
confirmed through production response that increased recovery
will be achieved.
An analysis of the estimated changes in quantities of proved
natural gas reserves attributed to the Forest Gulf of Mexico
operations for the years ended December 31, 2005, 2004 and
2003 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids (MBbls)
|
|
|
Gas (MMcf)
|
|
|
Total (MMcfe)
|
|
|
Balance at January 1, 2003
|
|
|
10,988
|
|
|
|
266,168
|
|
|
|
332,096
|
|
Revisions of previous estimates
|
|
|
(2,492
|
)
|
|
|
(14,565
|
)
|
|
|
(29,517
|
)
|
Extensions and discoveries
|
|
|
357
|
|
|
|
23,714
|
|
|
|
25,856
|
|
Production
|
|
|
(2,145
|
)
|
|
|
(58,785
|
)
|
|
|
(71,655
|
)
|
Purchases of reserves in place
|
|
|
4,649
|
|
|
|
78,815
|
|
|
|
106,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2003
|
|
|
11,357
|
|
|
|
295,347
|
|
|
|
363,489
|
|
Revisions of previous estimates
|
|
|
1,693
|
|
|
|
(2,860
|
)
|
|
|
7,298
|
|
Extensions and discoveries
|
|
|
630
|
|
|
|
14,449
|
|
|
|
18,229
|
|
Production
|
|
|
(3,230
|
)
|
|
|
(61,684
|
)
|
|
|
(81,064
|
)
|
Purchases of reserves in place
|
|
|
1,200
|
|
|
|
24,556
|
|
|
|
31,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
|
11,650
|
|
|
|
269,808
|
|
|
|
339,708
|
|
Revisions of previous estimates
|
|
|
3,123
|
|
|
|
4,815
|
|
|
|
23,553
|
|
Extensions and discoveries
|
|
|
504
|
|
|
|
5,639
|
|
|
|
8,663
|
|
Production
|
|
|
(2,783
|
)
|
|
|
(49,120
|
)
|
|
|
(65,818
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
|
12,494
|
|
|
|
231,142
|
|
|
|
306,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-65
FOREST
GULF OF MEXICO OPERATIONS
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES (Continued)
For the Years Ended December 31, 2005, 2004 and 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids (MBbls)
|
|
|
Gas (MMcf)
|
|
|
Total (MMcfe)
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2003
|
|
|
7,920
|
|
|
|
205,334
|
|
|
|
252,854
|
|
December 31, 2004
|
|
|
9,471
|
|
|
|
201,759
|
|
|
|
258,585
|
|
December 31, 2005
|
|
|
8,792
|
|
|
|
142,143
|
|
|
|
194,895
|
|
Standardized
Measure of Discounted Future Net Cash Flows
Future oil and gas sales and production and development costs
have been estimated using prices and costs in effect at the end
of the years indicated. The weighted average prices used for the
December 31, 2005, 2004, and 2003 calculations were $61.04,
$43.45 and $32.55 per barrel of oil and $10.08, $6.15 and
$5.97 per Mcf of gas, respectively. Future cash inflows
were reduced by estimated future development, abandonment and
production costs based on period-end costs. Future income tax
expenses are estimated using the statutory federal rate of 35%.
No deductions were made for general overhead, depletion,
depreciation, and amortization, or any indirect costs. All cash
flow amounts are discounted at 10%.
Changes in the demand for oil and natural gas, inflation, and
other factors make such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of the current market value of the
companys proved reserves.
The estimated standardized measure of discounted future net cash
flows relating to proved reserves at December 31, 2005,
2004 and 2003 is shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Future cash inflows
|
|
$
|
2,849,998
|
|
|
$
|
2,155,217
|
|
|
$
|
2,105,447
|
|
Future production costs
|
|
|
(226,248
|
)
|
|
|
(272,020
|
)
|
|
|
(272,335
|
)
|
Future development costs
|
|
|
(386,855
|
)
|
|
|
(357,592
|
)
|
|
|
(372,139
|
)
|
Future income taxes
|
|
|
(649,002
|
)
|
|
|
(412,477
|
)
|
|
|
(360,707
|
)
|
Future net cash flows
|
|
|
1,587,893
|
|
|
|
1,113,128
|
|
|
|
1,100,266
|
|
10% annual discount
|
|
|
(292,730
|
)
|
|
|
(187,291
|
)
|
|
|
(150,845
|
)
|
Standardized measure of discounted
future net cash flows relating to proved reserves
|
|
$
|
1,295,163
|
|
|
$
|
925,837
|
|
|
$
|
949,421
|
|
An analysis of the sources of changes in the standardized
measure of discounted future net cash flows relating to proved
reserves on the pricing basis described above for the years
ended December 31, 2005, 2004 and 2003 is shown below.
F-66
FOREST
GULF OF MEXICO OPERATIONS
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES (Continued)
For the Years Ended December 31, 2005, 2004 and 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Balance, beginning of period
|
|
$
|
925,837
|
|
|
$
|
949,421
|
|
|
$
|
648,040
|
|
Increase (decrease) in discounted
future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas, net of
production costs
|
|
|
(436,385
|
)
|
|
|
(426,405
|
)
|
|
|
(333,029
|
)
|
Net changes in prices and future
production costs
|
|
|
692,164
|
|
|
|
11,628
|
|
|
|
345,947
|
|
Net changes in future development
costs
|
|
|
(80,948
|
)
|
|
|
9,615
|
|
|
|
(82,874
|
)
|
Extensions, discoveries and
improved recovery
|
|
|
53,744
|
|
|
|
88,999
|
|
|
|
98,561
|
|
Previously estimated development
costs incurred during the period
|
|
|
87,970
|
|
|
|
70,027
|
|
|
|
74,690
|
|
Revisions of previous quantity
estimates
|
|
|
109,207
|
|
|
|
28,701
|
|
|
|
(104,674
|
)
|
Purchases of reserves in place
|
|
|
|
|
|
|
100,681
|
|
|
|
307,686
|
|
Accretion of discount
|
|
|
122,217
|
|
|
|
121,720
|
|
|
|
82,808
|
|
Net change in income taxes
|
|
|
(178,643
|
)
|
|
|
(28,550
|
)
|
|
|
(87,734
|
)
|
Balance, end of period
|
|
$
|
1,295,163
|
|
|
$
|
925,837
|
|
|
$
|
949,421
|
|
F-67