UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
Form 10-K
|
x
|
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the fiscal year ended December 31, 2009
|
o
|
TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
Commission
file number: 000-51719
LINN
ENERGY, LLC
(Exact
name of registrant as specified in its charter)
|
Delaware
|
65-1177591
|
|
(State
or other jurisdiction of
incorporation
or organization)
|
(I.R.S.
Employer
Identification
No.)
|
|
600
Travis, Suite 5100
Houston,
Texas
|
77002
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant’s
telephone number, including area code
(281)
840-4000
Securities
registered pursuant to Section 12(b) of the Act:
|
Title of each class
|
Name of each exchange on which
registered
|
|
|
Units
Representing Limited Liability Company Interests
|
The
NASDAQ Global Select Market
|
Securities registered pursuant to
Section 12(g) of the Act:
None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes x No o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange Act.
Yes o No x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes x No o
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Website, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during
the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files).
Yes o No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
Large
accelerated filer x Accelerated
filer o
Non-accelerated filer o
Smaller reporting company o
Indicate
by check-mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).
Yes o No x
The
aggregate market value of voting and non-voting common equity held by
non-affiliates of the registrant was approximately $2,303,614,114 on
June 30, 2009, based on $19.57 per unit, the last reported sales price of
the units on The NASDAQ Global Select Market on such date.
As of
January 29, 2010, there were 130,566,930 units outstanding.
Documents
Incorporated By Reference:
Certain
information called for in Items 10, 11, 12, 13 and 14 of Part III are
incorporated by reference from the registrant’s definitive proxy statement for
the annual meeting of unitholders to be held on April 27,
2010.
|
Page
|
|||
As
commonly used in the oil and natural gas industry and as used in this Annual
Report on Form 10-K, the following terms have the following
meanings:
Bbl. One stock
tank barrel or 42 United States gallons liquid volume.
Bcf. One billion
cubic feet.
Bcfe. One billion
cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one
Bbl of oil, condensate or natural gas liquids.
Btu. One British
thermal unit, which is the heat required to raise the temperature of a one-pound
mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
Development
well. A well drilled within the proved area of a reservoir to
the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well
found to be incapable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production would exceed production expenses
and taxes.
Field. An area
consisting of 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.
MBbls. One
thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. MBbls per
day.
Mcf. One thousand
cubic feet.
Mcfe. One thousand
cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one Bbl of oil, condensate or natural gas liquids.
MMBbls. One
million barrels of oil or other liquid hydrocarbons.
MMBoe. One million
barrels of oil equivalent, determined using a ratio of one Bbl of oil,
condensate or natural gas liquids to six Mcf.
MMBtu. One million
British thermal units.
MMcf. One million
cubic feet.
MMcf/d. MMcf per
day.
MMcfe. One million
cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one
Bbl of oil, condensate or natural gas liquids.
MMcfe/d. MMcfe per
day.
MMMBtu. One
billion British thermal units.
Net acres or net wells. The
sum of the fractional working interests owned in gross acres or gross wells, as
the case may be.
NGL. Natural gas
liquids, which are the hydrocarbon liquids contained within natural
gas.
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 exceeds
production expenses and taxes.
Proved developed
reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods or in which
the cost of the required equipment is relatively minor compared to the cost of a
new well. Additional reserves 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
in “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.
Proved
reserves. Reserves that by analysis of geoscience and
engineering data can be estimated with reasonable certainty to be economically
producible from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations prior to the
time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain. The project to extract
the hydrocarbons must have commenced or the operator must be reasonably certain
that it will commence the project within a reasonable time. In
accordance with Securities and Exchange Commission regulations, reserves at
December 31, 2009, were estimated using the average price during the
12-month period, determined as an unweighted average of the
first-day-of-the-month price for each month, unless prices are defined by
contractual arrangements, excluding escalations based upon future
conditions. In accordance with Securities and Exchange Commission
regulations, reserves for all prior years were estimated using year-end
prices.
Proved undeveloped drilling
location. A site on which a development well can be drilled
consistent with spacing rules for purposes of recovering proved undeveloped
reserves.
Proved undeveloped reserves
or
PUDs. 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. Reserves on undrilled
acreage are limited to those directly offsetting development spacing areas that
are reasonably certain of production when drilled, unless evidence using
reliable technology exists that establishes reasonable certainty of economic
producibility at greater distances. Undrilled locations can be
classified as having undeveloped reserves only if a development plan has been
adopted indicating that they are scheduled to be drilled within five years,
unless the specific circumstances justify a longer time. Estimates
for proved undeveloped reserves are not attributed to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, or by other evidence
using reliable technology establishing reasonable certainty.
Recompletion. The
completion for production of an existing wellbore in another formation from that
which the well has been previously completed.
Reservoir. A
porous and permeable underground formation containing a natural accumulation of
economically productive natural gas and/or oil that is confined by impermeable
rock or water barriers and is individual and separate from other
reserves.
Royalty
interest. An interest that entitles the owner of such interest
to a share of the mineral production from a property or to a share of the
proceeds there from. It does not contain the rights and obligations
of operating the property and normally does not bear any of the costs of
exploration, development and operation of the property.
Standardized measure of discounted
future net cash flows. The present value of estimated future
net revenues to be generated from the production of proved reserves, determined
in accordance with the regulations of the Securities and Exchange Commission,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expenses or
depreciation, depletion and amortization; discounted using an annual discount
rate of 10%.
Tcfe. One trillion
cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one Bbl of oil, condensate or natural gas liquids.
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, natural gas and NGL regardless of whether such acreage contains proved
reserves.
Unproved
reserves. Reserves that are considered less certain to be
recovered than proved reserves. Unproved reserves may be further
sub-classified to denote progressively increasing uncertainty of recoverability
and include probable reserves and possible reserves.
Working
interest. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.
Workover. Maintenance
on a producing well to restore or increase production.
This
Annual Report on Form 10-K contains forward-looking statements based on
expectations, estimates and projections as of the date of this
filing. These statements by their nature are subject to risks,
uncertainties and assumptions and are influenced by various
factors. As a consequence, actual results may differ materially from
those expressed in the forward-looking statements. For more
information see “Forward-Looking Statements” included at the end of this
Item 1. “Business” and see also Item 1A. “Risk Factors.”
References
When
referring to Linn Energy, LLC (“LINN Energy” or the “Company”), the intent is to
refer to LINN Energy and its consolidated subsidiaries as a whole or on an
individual basis, depending on the context in which the statements are
made.
A
reference to a “Note” herein refers to the accompanying Notes to Consolidated
Financial Statements contained in Item 8. “Financial Statements and
Supplementary Data.”
Overview
LINN
Energy’s mission is to acquire, develop and maximize cash flow from a growing
portfolio of long-life oil and natural gas assets. LINN Energy is an
independent oil and natural gas company that began operations in March 2003 and
completed its initial public offering (“IPO”) in January 2006. The
Company’s properties are located in the United States, primarily in the
Mid-Continent, California and the Permian Basin.
Proved
reserves at December 31, 2009, were 1,712 Bcfe, of which approximately 36%
were oil, 45% were natural gas and 19% were natural gas liquids
(“NGL”). Approximately 71% were classified as proved developed, with
a total standardized measure of discounted future net cash flows of $1.72
billion. At December 31, 2009, the Company operated 4,688, or
68%, of its 6,931 gross productive wells and had an average proved reserve-life
index of approximately 22 years, based on the December 31, 2009, reserve
report and annualized production for the three months ended December 31,
2009.
In
January 2010, the Company completed an acquisition of oil and natural gas
properties in the Anadarko and Permian Basins for a contract price of $154.5
million. See “Recent Developments” below for additional
details. On a pro forma basis, including this acquisition, total
proved reserves at December 31, 2009, were 1,785 Bcfe, of which
approximately 37% were oil, 44% were natural gas and 19% were NGL.
Strategy
The
Company’s primary goal is to provide stability and growth of distributions for
the long-term benefit of its unitholders. The following is a summary
of the key elements of the Company’s business strategy:
|
|
·
|
grow
through acquisition of long-life, high quality
properties;
|
|
|
·
|
efficiently
operate and develop acquired properties;
and
|
|
|
·
|
reduce
cash flow volatility through commodity price and interest rate
hedging.
|
The
Company’s business strategy is discussed in more detail below.
Grow
Through Acquisition of Long-Life, High Quality Properties
The
Company’s acquisition program targets oil and natural gas properties that are
financially accretive and offer stable, long-life, high quality production with
relatively predictable decline curves, as well as lower-risk development
opportunities. The Company evaluates acquisitions based on decline
profile, reserve life, operational efficiency, field cash flow, development
costs and rate of return. As part of this strategy, the Company
continually
seeks to
optimize its asset portfolio, which may include the divestiture of noncore
assets. This allows the Company to redeploy capital into projects to
develop lower-risk, long-life and low-decline properties that are better suited
to its business strategy.
From
inception through the date of this report, excluding 15 acquisitions comprising
the Appalachian Basin properties sold in July 2008, the Company has completed 13
acquisitions of working and royalty interests in oil and natural gas properties
and related gathering and pipeline assets. Total acquired proved
reserves were approximately 1.8 Tcfe at the time of acquisition at an
acquisition cost of approximately $2.15 per Mcfe. The Company
finances acquisitions with a combination of funds from equity and debt
offerings, bank borrowings and cash generated from operations. See
Note 2 for additional details about the Company’s acquisitions and
divestitures.
Efficiently
Operate and Develop Acquired Properties
The
Company has centralized the operation of its acquired properties into defined
operating regions to minimize operating costs and maximize production and
capital efficiency. The Company maintains a large inventory of
drilling and optimization projects within each region to achieve organic growth
from its capital development program. The Company seeks to be the
operator of its properties so that it can develop drilling programs and
optimization projects that not only replace production, but add value through
reserve and production growth and future operational synergies. The
development program is focused on lower-risk, repeatable drilling opportunities
to maintain and/or grow cash flow. Many of the wells are completed in
multiple producing zones with commingled production and long economic
lives. In addition, the Company seeks to deliver attractive financial
returns by leveraging its experienced workforce and scalable
infrastructure. For 2010, the Company estimates its capital
expenditures, excluding acquisitions, will be between $150.0 million and $175.0
million. This estimate is under continuous review and is subject to
ongoing adjustment. The Company expects to fund these capital
expenditures with cash flow from operations.
Reduce
Cash Flow Volatility Through Commodity Price and Interest Rate
Hedging
An
important part of the Company’s business strategy includes hedging a significant
portion of its forecasted production to reduce exposure to fluctuations in the
prices of oil, natural gas and NGL and provide long-term cash flow
predictability to pay distributions, service debt and manage its
business. By removing a significant portion of the price volatility
associated with future production, the Company expects to mitigate, but not
eliminate, the potential effects of variability in cash flow from operations due
to fluctuations in commodity prices.
These
transactions are primarily in the form of swap contracts, put options and
collars that are designed to provide a fixed price (swap contracts), fixed price
floor with opportunity for upside (put options) or range of prices between a
price floor and a price ceiling (collars) that the Company will receive as
compared to floating market prices. The Company has derivative
contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and
$82.50 per Bbl for oil and $8.66 per MMBtu and $9.25 per MMBtu for natural gas,
respectively. Additionally, the Company has derivative contracts in
place covering substantially all of its exposure to the Mid-Continent natural
gas basis differential.
In
addition, the Company enters into derivative contracts in the form of interest
rate swaps to minimize the effects of fluctuations in interest
rates. Currently, the Company utilizes London Interbank Offered Rate
(“LIBOR”) swaps to convert the borrowing rate on indebtedness under its Credit
Facility (as defined in Note 6) from a floating rate to a fixed
rate. At January 29, 2010, the Company had LIBOR swaps in place
at an average fixed rate of 3.85% through January 2014. For
additional details about the Company’s interest rate swap agreements and
commodity derivative contracts, see Item 7. “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and Item 7A.
“Quantitative and Qualitative Disclosures About Market Risk.” See
also Note 7 and Note 8.
Recent
Developments
Commodity
Derivatives
In
February 2010, the Company entered into fixed price oil swaps on an
additional 5,250 Bbls per day at a price of $100.00 per Bbl for the years
ending December 31, 2012, and December 31, 2013, bringing the
Company’s total such fixed price oil swaps to swaps on 7,250 Bbls per
day. The Company has derivative contracts that extend the swaps for
each of the years ending December 31, 2014, December 31, 2015, and
December 31, 2016, if the counterparties determine that the strike prices
are in-the-money on a designated date in each respective preceding
year. The extension for each year is exercisable without respect to
the other years. See Item 7. “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” for additional
details.
Acquisitions
On
January 29, 2010, the Company completed the acquisition of certain oil and
natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and
the Permian Basin in Texas and New Mexico, from certain affiliates of Merit
Energy Company (“Merit”) for a contract price of $154.5 million. The
transaction was financed with borrowings under the Company’s Credit
Facility. The acquisition provides a strategic addition to the
Company’s asset portfolio in the Permian Basin and Mid-Continent, and includes
approximately 12 MMBoe (73 Bcfe) of proved reserves as of the acquisition date,
primarily oil.
On
August 31, 2009, and September 30, 2009, the Company completed the
acquisitions of certain oil and natural gas properties located in the Permian
Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian
Corporation (collectively referred to as “Forest”). The Company paid
$114.4 million in cash, net of cash received from Forest post-closing, and
recorded a receivable from Forest, resulting in total consideration for the
acquisitions of approximately $113.7 million. The transactions were
financed with borrowings under the Company’s Credit Facility. The
acquisitions represent a strategic entry into the Permian Basin for the Company,
and include approximately 10 MMBoe (62 Bcfe) of proved reserves, primarily
oil.
Distributions
On
January 27, 2010, the Company’s Board of Directors declared a cash
distribution of $0.63 per unit with respect to the fourth quarter of
2009. The distribution, totaling approximately $82.3 million, was
paid on February 12, 2010, to unitholders of record as of the close of
business on February 5, 2010.
Operating
Regions
Inclusive
of the properties acquired from Merit in January 2010 (see “Acquisitions”
above), the Company’s properties are located in four regions in the United
States:
|
|
·
|
Mid-Continent
Deep, which includes the Texas Panhandle Deep Granite Wash formation and
deep formations in Oklahoma and
Kansas;
|
|
|
·
|
Mid-Continent
Shallow, which includes the Texas Panhandle Brown Dolomite formation and
shallow formations in Oklahoma, Louisiana and
Illinois;
|
|
|
·
|
California,
which includes the Brea Olinda Field of the Los Angeles Basin;
and
|
|
|
·
|
Permian
Basin, which includes areas in West Texas and Southeast New
Mexico.
|
Mid-Continent
Deep
The
Mid-Continent Deep region includes properties in the Deep Granite Wash formation
in the Texas Panhandle, which produces at depths ranging from 8,900 feet to
16,000 feet, as well as properties in Oklahoma and Kansas, which produce at
depths of more than 8,000 feet. Mid-Continent Deep proved reserves
represented approximately 47% of total proved reserves at December 31,
2009, of which 71% were classified as proved developed reserves.
This
region produced 135 MMcfe/d, or 62%, of the Company’s 2009 average daily
production. During 2009, the Company invested approximately $99.3
million to drill in this region. During 2010, the Company anticipates
spending approximately 60% of its total capital budget for development
activities in the Mid-Continent Deep region.
Mid-Continent
Shallow
The
Mid-Continent Shallow region includes properties producing from the Brown
Dolomite formation in the Texas Panhandle, which produces at depths of
approximately 3,200 feet and properties in Oklahoma, Louisiana and Illinois,
which produce at depths of less than 8,000 feet. Mid-Continent
Shallow proved reserves represented approximately 38% of total proved reserves
at December 31, 2009, of which 66% were classified as proved developed
reserves. This region produced 67 MMcfe/d, or 31%, of the Company’s
2009 average daily production. During 2009, the Company invested
approximately $21.0 million to drill in this region. During 2010, the
Company anticipates spending approximately 20% of its total capital budget for
development activities in the Mid-Continent Shallow region.
To more
efficiently transport its natural gas in the Mid-Continent Deep and
Mid-Continent Shallow regions to market, the Company owns and operates a network
of natural gas gathering systems comprised of approximately 900 miles of
pipeline and associated compression and metering facilities that connect to
numerous sales outlets in the Texas Panhandle.
California
The
California region consists of the Brea Olinda Field of the Los Angeles
Basin. The Brea Olinda Field was discovered in 1880 and produces from
the shallow Pliocene formation to the deeper Miocene formation at depths of
1,000 feet to 7,500 feet. California proved reserves represented
approximately 11% of total proved reserves at December 31, 2009, of which
94% were classified as proved developed reserves. This region
produced 14 MMcfe/d, or 6%, of the Company’s 2009 average daily
production.
Permian
Basin
The
Permian Basin is one of the largest and most prolific oil and natural gas basins
in the United States. The Company’s properties are located in West
Texas and Southeast New Mexico and produce at depths ranging from 2,000 feet to
9,000 feet. Permian Basin proved reserves represented approximately
4% of total proved reserves at December 31, 2009, of which 53% were
classified as proved developed reserves. The properties that comprise
this region as of December 31, 2009, were acquired in the third quarter of 2009
(see “Acquisitions” above). This region produced 2 MMcfe/d, or 1%, of
the Company’s 2009 average daily production. During 2009, the Company
invested approximately $0.1 million to drill in this region. During
2010, the Company anticipates spending approximately 20% of its total capital
budget for development activities in the Permian Basin region.
Drilling
and Acreage
The
following sets forth the wells drilled in the Mid-Continent Deep, Mid-Continent
Shallow, California and Permian Basin operating regions during the periods
indicated (“gross” refers to the total wells in which the Company had a working
interest and “net” refers to gross wells multiplied by its working
interest):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Gross
wells:
|
||||||||||||
|
Productive
|
72 | 304 | 136 | |||||||||
|
Dry
|
1 | 2 | 2 | |||||||||
| 73 | 306 | 138 | ||||||||||
|
Net
development wells:
|
||||||||||||
|
Productive
|
35 | 189 | 112 | |||||||||
|
Dry
|
1 | 1 | 2 | |||||||||
| 36 | 190 | 114 | ||||||||||
|
Net
exploratory wells:
|
||||||||||||
|
Productive
|
— | — | — | |||||||||
|
Dry
|
— | — | — | |||||||||
| — | — | — | ||||||||||
The
totals above do not include 25, 23 and 25 lateral segments added to existing
vertical wellbores in the Mid-Continent Shallow region during the years ended
December 31, 2009, December 31, 2008, and December 31, 2007,
respectively. The total wells above exclude 45 and 115 gross wells
(45 and 105 net wells) drilled in the Appalachian Basin during the years ended
December 31, 2008, and December 31, 2007, respectively. The
Company sold its Appalachian Basin properties in July 2008. At
December 31, 2009, the Company had one gross (one net) well in process (no
wells were temporarily suspended).
The
information should not be considered indicative of future performance, nor
should it be assumed that there is necessarily any correlation between the
number of productive wells drilled and the quantities or economic value of
reserves found. Productive wells are those that produce commercial
quantities of oil, natural gas or NGL, regardless of whether they generate a
reasonable rate of return.
The
following sets forth information about the Company’s drilling locations and net
acres of leasehold interests as of December 31, 2009:
|
Total (1)
|
||||
|
Proved
undeveloped
|
1,241 | |||
|
Other
locations
|
3,050 | |||
|
Total
drilling locations
|
4,291 | |||
|
Leasehold
interests – net acres (in thousands)
|
702 | |||
(1) Does
not include optimization projects.
As shown
in the table above, as of December 31, 2009, the Company had 1,241 proved
undeveloped drilling locations (specific drilling locations as to which the
independent engineering firm, DeGolyer and MacNaughton, assigned proved
undeveloped reserves as of such date) and the Company had identified 3,050
additional unproved drilling locations (specific drilling locations as to which
DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that
the Company has under existing leases. As successful development
wells frequently result in the reclassification of adjacent lease acreage from
unproved to proved, the Company expects that a significant
number of
its unproved drilling locations will be reclassified as proved drilling
locations prior to the actual drilling of these locations.
Productive
Wells
The
following table sets forth information relating to the productive wells in which
the Company owned a working interest as of December 31,
2009. Productive wells consist of producing wells and wells capable
of production, including wells awaiting pipeline or other connections to
commence deliveries. “Gross” wells refers to the total number of
producing wells in which the Company has an interest, and “net” wells refers to
the sum of its fractional working interests owned in gross wells. The
number of wells below does not include approximately 2,100 productive wells in
which the Company owns a royalty interest only.
|
Natural
Gas Wells
|
Oil
Wells
|
Total
Wells
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Operated
(1)
|
1,947 | 1,534 | 2,741 | 2,523 | 4,688 | 4,057 | ||||||||||||||||||
|
Nonoperated
(2)
|
1,201 | 207 | 1,042 | 72 | 2,243 | 279 | ||||||||||||||||||
| 3,148 | 1,741 | 3,783 | 2,595 | 6,931 | 4,336 | |||||||||||||||||||
|
(1)
|
10
operated wells had multiple completions at December 31,
2009.
|
|
(2)
|
Three
nonoperated wells had multiple completions at December 31,
2009.
|
Developed
and Undeveloped Acreage
The
following sets forth information as of December 31, 2009, relating to
leasehold acreage:
|
Developed
Acreage
|
Undeveloped
Acreage
|
Total
Acreage
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||||||
|
Leasehold
acreage
|
1,462 | 648 | 90 | 54 | 1,552 | 702 | ||||||||||||||||||
Production,
Price and Cost History
The
results of the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc.
(“Mid Atlantic”) operations are classified as discontinued operations for all
periods presented (see Note 2 for additional
information). Unless otherwise indicated, results of operations
information presented herein relates only to continuing operations.
The
Company’s natural gas production is primarily sold under market sensitive price
contracts, which typically sell at a differential to New York Mercantile
Exchange (“NYMEX”), Panhandle Eastern Pipeline (“PEPL”), or El Paso Permian
Basin natural gas prices due to the Btu content and the proximity to major
consuming markets. The Company’s natural gas production is sold to
purchasers under percentage-of-proceeds contracts, percentage-of-index contracts
or spot price contracts. By the terms of the percentage-of-proceeds
contracts, the Company receives a percentage of the resale price received by the
purchaser for sales of residual natural gas and NGL recovered after
transportation and processing of natural gas. These purchasers sell
the residual natural gas and NGL based primarily on spot market
prices. Under percentage-of-index contracts, the price per MMBtu the
Company receives for natural gas is tied to indexes published in Gas Daily or Inside FERC Gas Market Report.
Although exact percentages vary daily, as of December 31, 2009,
approximately 80% of the Company’s natural gas and NGL production was sold under
short-term contracts at market-sensitive or spot prices. At
December 31, 2009, the Company had natural gas throughput delivery
commitments under long-term contracts of approximately 2,102 MMcf, 1,045 MMcf
and 784 MMcf for the years ended December 31, 2010, December 31, 2011,
and December 31, 2012, respectively.
The
Company’s oil production is primarily sold under market sensitive contracts,
which typically sell at a differential to NYMEX, and as of December 31,
2009, approximately 75% of its oil production was sold under short-term
contracts. At December 31, 2009, the Company had no delivery
commitments for oil production.
As
discussed in the “Strategy” section above, the Company enters into derivative
contracts primarily in the form of swap contracts, put options and collars to
reduce the impact of commodity price volatility on its cash flow from
operations. By removing a significant portion of the price volatility
associated with future production, the Company expects to mitigate, but not
eliminate, the potential effects of variability in cash flow due to fluctuations
in commodity prices.
The
following sets forth information regarding average daily production, average
prices and average costs, from continuing operations, for each of the periods
indicated:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Average
daily production:
|
||||||||||||
|
Natural
gas (MMcf/d)
|
125 | 124 | 51 | |||||||||
|
Oil
(MBbls/d)
|
9.0 | 8.6 | 3.4 | |||||||||
|
NGL
(MBbls/d)
|
6.5 | 6.2 | 2.7 | |||||||||
|
Total
(MMcfe/d)
|
218 | 212 | 87 | |||||||||
|
Weighted average prices
(hedged): (1)
|
||||||||||||
|
Natural
gas (Mcf)
|
$ | 8.27 | $ | 8.42 | $ | 8.36 | ||||||
|
Oil
(Bbl)
|
$ | 110.94 | $ | 80.92 | $ | 67.07 | ||||||
|
NGL
(Bbl)
|
$ | 28.04 | $ | 57.86 | $ | 55.51 | ||||||
|
Weighted average prices
(unhedged): (2)
|
||||||||||||
|
Natural
gas (Mcf)
|
$ | 3.51 | $ | 7.39 | $ | 6.39 | ||||||
|
Oil
(Bbl)
|
$ | 55.25 | $ | 92.78 | $ | 66.44 | ||||||
|
NGL
(Bbl)
|
$ | 28.04 | $ | 57.86 | $ | 55.51 | ||||||
|
Average
NYMEX prices:
|
||||||||||||
|
Natural
gas (MMBtu)
|
$ | 3.99 | $ | 9.04 | $ | 6.86 | ||||||
|
Oil
(Bbl)
|
$ | 61.94 | $ | 99.65 | $ | 72.34 | ||||||
|
Costs
per Mcfe of production:
|
||||||||||||
|
Lease
operating expenses
|
$ | 1.67 | $ | 1.49 | $ | 1.31 | ||||||
|
Transportation
expenses
|
$ | 0.23 | $ | 0.23 | $ | 0.17 | ||||||
|
General
and administrative expenses (3)
|
$ | 1.08 | $ | 1.00 | $ | 1.61 | ||||||
|
Depreciation,
depletion and amortization
|
$ | 2.53 | $ | 2.50 | $ | 2.16 | ||||||
|
Taxes,
other than income taxes
|
$ | 0.35 | $ | 0.79 | $ | 0.70 | ||||||
|
(1)
|
Includes
the effect of realized gains on derivatives of $401.0 million (excluding
$49.0 million realized net gains on canceled contracts), $9.4 million
(excluding $81.4 million realized losses on canceled contracts) and $37.3
million for the years ended December 31, 2009, December 31,
2008, and December 31, 2007, respectively. The Company
utilizes oil puts to hedge revenues associated with its NGL production;
therefore, all realized gains on oil derivative contracts are included in
weighted average oil prices, rather than weighted average NGL
prices.
|
|
(2)
|
Does
not include the effect of realized gains (losses) on
derivatives.
|
|
(3)
|
General
and administrative expenses for the years ended December 31, 2009,
December 31, 2008, and December 31, 2007, include approximately
$14.7 million, $14.6 million and $13.5 million, respectively, of noncash
unit-based compensation expenses. Excluding these amounts,
general and administrative expenses for the years ended December 31,
2009, December 31, 2008, and December 31, 2007, were $0.90 per
Mcfe, $0.81 per Mcfe and $1.19 per Mcfe, respectively. This
measure is not in accordance with United States Generally Accepted
Accounting Principles (“GAAP”) and thus is a non-GAAP measure, used by
management to analyze the Company’s
performance.
|
Reserve
Data
Modernization
of Oil and Natural Gas Reporting Requirements
Effective
for fiscal years ending on or after December 31, 2009, the Securities and
Exchange Commission (“SEC”) approved revisions designed to modernize reserve
reporting requirements for oil and natural gas companies. In
addition, effective for the same period, the Financial Accounting Standards
Board issued Accounting Standards Codification Update 2010-03, “Extractive Activities – Oil and Gas
(Topic 932) – Oil and Gas Reserve Estimation and Disclosures,” to provide
consistency with the new SEC rules. The Company adopted the new
requirements effective December 31, 2009. The most significant
amendments to the requirements include the following:
|
|
·
|
commodity
prices – economic producibility of reserves estimated using the average
price during the 12-month period, determined as an unweighted average of
the first-day-of-the-month price for each month, unless prices are defined
by contractual arrangements, excluding escalations based upon future
conditions;
|
|
|
·
|
disclosure
of unproved reserves – probable and possible reserves may be disclosed
separately on a voluntary basis;
|
|
|
·
|
proved
undeveloped reserve guidelines – reserves may be classified as proved
undeveloped if there is a high degree of confidence that the quantities
will be recovered;
|
|
|
·
|
reserve
estimation using new technologies – reserves may be estimated through the
use of reliable technology in addition to flow tests and production
history; and
|
|
|
·
|
nontraditional
resources –
the definition of oil and natural gas producing activities were expanded
and focus on the marketable product rather than the method of
extraction.
|
Proved
Reserves
The
following sets forth estimated proved oil, natural gas and NGL reserves and the
standardized measure of discounted future net cash flows at December 31,
2009, based on reserve reports prepared by independent engineers DeGolyer and
MacNaughton:
|
Estimated
proved developed reserves:
|
||||
|
Natural
gas (Bcf)
|
549 | |||
|
Oil
(MMBbls)
|
78 | |||
|
NGL
(MMBbls)
|
34 | |||
|
Total
(Bcfe)
|
1,220 | |||
|
Estimated proved undeveloped
reserves: (1)
|
||||
|
Natural
gas (Bcf)
|
225 | |||
|
Oil
(MMBbls)
|
24 | |||
|
NGL
(MMBbls)
|
20 | |||
|
Total
(Bcfe)
|
492 | |||
|
Estimated
total proved reserves (Bcfe)
|
1,712 | |||
|
Proved
developed reserves as a percentage of total proved
reserves
|
71 | % | ||
|
Standardized
measure of discounted future net cash flows (in millions) (2)
|
$ | 1,723 | ||
|
Representative NYMEX prices:
(3)
|
||||
|
Natural
gas (MMBtu)
|
$ | 3.87 | ||
|
Oil
(Bbl)
|
$ | 61.05 | ||
|
(1)
|
During
the year ended December 31, 2009, the Company incurred approximately
$52.7 million in capital expenditures to convert 33 Bcfe of reserves
previously classified as proved undeveloped into proved developed reserves
at December 31, 2009.
|
|
(2)
|
This
measure is not intended to represent the market value of estimated
reserves.
|
|
(3)
|
In
accordance with SEC regulations, reserves were estimated using the average
price during the 12-month period, determined as an unweighted average of
the first-day-of-the-month price for each month, unless prices are defined
by contractual arrangements, excluding escalations based upon future
conditions.
|
Reserve
engineering is inherently a subjective process of estimating underground
accumulations of oil, natural gas and NGL that cannot be measured
exactly. The accuracy of any reserve estimate is a function of the
quality of available data and engineering and geological interpretation and
judgment. Accordingly, reserve estimates may vary from the quantities
of oil, natural gas and NGL that are ultimately recovered. Future
prices received for production may vary, perhaps significantly, from the prices
assumed for the purposes of estimating the standardized measure of discounted
future net cash flows. The standardized measure of discounted future
net cash flows should not be construed as the market value of the reserves at
the dates shown. The 10% discount factor required to be used under
the provisions of applicable accounting standards may not be the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and natural gas
industry. The standardized measure of discounted future net cash
flows is materially affected by assumptions about the timing of future
production, which may prove to be inaccurate.
The
reserve estimates reported herein were prepared by independent engineers
DeGolyer and MacNaughton. The process performed by the independent
engineers to prepare reserve amounts included their estimation of reserve
quantities, future producing rates, future net revenue and the present value of
such future net revenue, based in part on data provided by the
Company. When preparing the reserve estimates, the independent
engineering firm did not independently verify the accuracy and completeness of
information and data furnished by the Company with respect to ownership
interests, production, well test data, historical costs of operation and
development, product prices, or any agreements relating to current and future
operations of the properties and sales of production. However, if in
the course of their work, something came to their attention that brought into
question the validity or sufficiency of any such information or data, they did
not rely on such information or data until they had satisfactorily resolved
their questions relating thereto. The estimates of reserves conform
to the guidelines of the SEC, including the criteria of “reasonable certainty,”
as it pertains to expectations about the recoverability of reserves in future
years. The independent engineering firm also prepared estimates with
respect to reserve categorization, using the definitions for proved reserves set
forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff
interpretations and guidance.
The
Company’s internal control over the preparation of reserve estimates is a
process designed to provide reasonable assurance regarding the reliability of
the Company’s reserve estimates in accordance with SEC
regulations. The preparation of reserve estimates was overseen by the
Company’s Reservoir Engineering Advisor, who has Master of Petroleum Engineering
and Master of Business Administration degrees and more than 25 years of oil and
natural gas industry experience. The reserve estimates were reviewed
and approved by the Company’s senior engineering staff and management, with
final approval by its Senior Vice President and Chief Operating
Officer. For additional information regarding estimates of reserves,
including the standardized measure of discounted future net cash flows, see
“Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial
Statements and Supplementary Data.”
Operational
Overview
General
The
Company seeks to be the operator of its properties so that it can control the
drilling programs that not only replace production, but add value through the
growth of reserves and future operational synergies. Many of the
Company’s wells are completed in multiple producing zones with commingled
production and long economic lives.
Principal
Customers
For the
year ended December 31, 2009, sales of oil, natural gas and NGL to DCP
Midstream Partners, LP, Enbridge Energy Partners, L.P. and ConocoPhillips
accounted for approximately 25%, 19% and 12%, respectively, of the Company’s
total volumes, or 56% in the aggregate. If the Company were to lose
any one of its major oil and natural gas purchasers, the loss could temporarily
cease or delay production and sale of its oil and natural gas in
that
particular
purchaser’s service area. If the Company were to lose a purchaser, it
believes it could identify a substitute purchaser. However, if one or
more of these large purchasers ceased purchasing oil and natural gas altogether,
it could have a detrimental effect on the oil and natural gas market in general
and on the volume of oil and natural gas that the Company is able to
sell.
Competition
The oil
and natural gas industry is highly competitive. The Company
encounters strong competition from other independent operators and master
limited partnerships in acquiring properties, contracting for drilling and other
related services and securing trained personnel. The Company is also
affected by competition for drilling rigs and the availability of related
equipment. In the past, the oil and natural gas industry has
experienced shortages of drilling rigs, equipment, pipe and personnel, which has
delayed development drilling and has caused significant price
increases. The Company is unable to predict when, or if, such
shortages may occur or how they would affect its drilling program.
Operating
Hazards and Insurance
The oil
and natural gas industry involves a variety of operating hazards and risks that
could result in substantial losses from, among other things, injury or loss of
life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, cleanup responsibilities,
regulatory investigation and penalties and suspension of
operations. The Company may be liable for environmental damages
caused by previous owners of property it purchases and leases. As a
result, the Company may incur substantial liabilities to third parties or
governmental entities, the payment of which could reduce or eliminate funds
available for acquisitions, development or distributions, or result in the loss
of properties. In addition, the Company participates in wells on a
nonoperated basis and therefore may be limited in its ability to control the
risks associated with the operation of such wells.
In
accordance with customary industry practices, the Company maintains insurance
against some, but not all, potential losses. The Company cannot
provide assurance that any insurance it obtains will be adequate to cover any
losses or liabilities. The Company has elected to self-insure for
certain items for which it has determined that the cost of available insurance
is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. The
occurrence of an event not fully covered by insurance could have a material
adverse effect on the Company’s financial position and results of
operations. For more information about potential risks that could
affect the Company see Item 1A. “Risk Factors.”
Title
to Properties
Prior to
the commencement of drilling operations, the Company conducts a title
examination and performs curative work with respect to significant
defects. To the extent title opinions or other investigations reflect
title defects on those properties the Company is typically responsible for
curing any title defects at its expense prior to commencing drilling
operations. Prior to completing an acquisition of producing leases,
the Company performs title reviews on the most significant leases and, depending
on the materiality of properties, the Company may obtain a title opinion or
review previously obtained title opinions. As a result, the Company
has obtained title opinions on a significant portion of its properties and
believes that it has satisfactory title to its producing properties in
accordance with standards generally accepted in the industry. Oil and
natural gas properties are subject to customary royalty and other interests,
liens for current taxes and other burdens which do not materially interfere with
the use of or affect the carrying value of the properties.
Seasonal
Nature of Business
Seasonal
weather conditions and lease stipulations can limit the drilling and producing
activities and other operations in regions of the United States in which the
Company operates. These seasonal conditions can pose challenges for
meeting the well drilling objectives and increase competition for equipment,
supplies and personnel,
which
could lead to shortages and increase costs or delay operations. For
example, Company operations in all regions may be impacted by ice and snow in
the winter and by electrical storms and high temperatures in the spring and
summer, as well as by wild fires in the fall.
The
demand for natural gas typically decreases during the summer months and
increases during the winter months. Seasonal anomalies sometimes
lessen this fluctuation. In addition, certain natural gas users
utilize natural gas storage facilities and purchase some of their anticipated
winter requirements during the summer, which can also lessen seasonal demand
fluctuations.
Environmental
Matters and Regulation
The
Company’s operations are subject to stringent federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. The Company’s
operations are subject to the same environmental laws and regulations as other
companies in the oil and natural gas industry. These laws and
regulations may:
|
|
·
|
require
the acquisition of various permits before drilling
commences;
|
|
|
·
|
require
the installation of expensive pollution control
equipment;
|
|
|
·
|
restrict
the types, quantities and concentration of various substances that can be
released into the environment in connection with drilling and production
activities;
|
|
|
·
|
limit
or prohibit drilling activities on lands lying within wilderness, wetlands
and other protected areas;
|
|
|
·
|
require
remedial measures to prevent pollution from former operations, such as pit
closure and plugging of abandoned
wells;
|
|
|
·
|
impose
substantial liabilities for pollution resulting from operations;
and
|
|
|
·
|
with
respect to operations affecting federal lands or leases, require
preparation of a Resource Management Plan, an Environmental Assessment,
and/or an Environmental Impact
Statement.
|
These
laws, rules and regulations may also restrict the rate of oil, natural gas and
NGL production below the rate that would otherwise be possible. The
regulatory burden on the industry increases the cost of doing business and
consequently affects profitability. Additionally, Congress and
federal and state agencies frequently revise environmental laws and regulations,
and any changes that result in more stringent and costly waste handling,
disposal and cleanup requirements for the oil and natural gas industry could
have a significant impact on operating costs.
The
environmental laws and regulations applicable to the Company and its operations
include, among others, the following United States federal laws and
regulations:
|
|
·
|
Clean
Air Act, and its amendments, which governs air
emissions;
|
|
|
·
|
Clean
Water Act, which governs discharges to and excavations within the waters
of the United States;
|
|
|
·
|
Comprehensive
Environmental Response, Compensation and Liability Act, which imposes
liability where hazardous releases have occurred or are threatened to
occur (commonly known as
“Superfund”);
|
|
|
·
|
Energy
Independence and Security Act of 2007, which prescribes new fuel economy
standards and other energy saving
measures;
|
|
|
·
|
National
Environmental Policy Act, which governs oil and natural gas production
activities on federal lands;
|
|
|
·
|
Resource
Conservation and Recovery Act, which governs the management of solid
waste;
|
|
|
·
|
Safe
Drinking Water Act, which governs the underground injection and disposal
of wastewater; and
|
|
|
·
|
United
States Department of Interior regulations, which impose liability for
pollution cleanup and damages.
|
Various
states regulate the drilling for, and the production, gathering and sale of,
oil, natural gas and NGL, including imposing production taxes and requirements
for obtaining drilling permits. States also regulate the method of
developing new fields, the spacing and operation of wells and the prevention of
waste of resources. States may regulate rates of production and may
establish maximum daily production allowables from natural gas wells
based
on market
demand or resource conservation, or both. States do not regulate
wellhead prices or engage in other similar direct economic regulation, but there
can be no assurance that they will not do so in the future. The
effect of these regulations may be to limit the amounts of oil, natural gas and
NGL that may be produced from the Company’s wells and to limit the number of
wells or locations it can drill. The oil and natural gas industry is
also subject to compliance with various other federal, state and local
regulations and laws. Some of those laws relate to occupational
safety, resource conservation and equal opportunity employment.
The
Company believes that it substantially complies with all current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on its financial condition
or results of operations. Future regulatory issues that could impact
the Company include new rules or legislation regulating greenhouse gas emissions
to address climate change, such as a proposed cap-and-trade program and the
Environmental Protection Agency’s (“EPA”) recent endangerment finding regarding
several greenhouse gases, including carbon dioxide, as well as regulations
imposing reporting obligations on, or otherwise limiting, the hydraulic
fracturing process.
In June
2009, the United States House of Representatives passed the American Clean
Energy and Security Act of 2009, also known as the Waxman-Markey
Bill. The United States Senate’s version, The Clean Energy Jobs and
American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not
passed. Although these bills include several differences that require
reconciliation before becoming law, both bills contain the basic feature of
establishing a cap-and-trade system for restricting greenhouse gas emissions in
the United States. Under such system, certain sources of greenhouse
gas emissions would be required to obtain greenhouse gas emission allowances
corresponding to their annual emissions of greenhouse gases. The
number of emission allowances issued each year would decline as necessary to
meet overall emission reduction goals. As the number of greenhouse
gas emission allowances declines each year, the cost or value of allowances is
expected to escalate significantly. The ultimate outcome of this
legislative initiative remains uncertain. In addition to the pending
climate legislation, the EPA has issued greenhouse gas monitoring and reporting
regulations that went into effect January 1, 2010, and require reporting by
regulated facilities by March 2011 and annually thereafter. Beyond
measuring and reporting, the EPA issued an “Endangerment Finding” under section
202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the
public health and welfare of current and future generations. The EPA
has proposed regulation that would require permits for and reductions in
greenhouse gas emissions for certain facilities, and may issue final rules this
year. Any laws or regulations that may be adopted to restrict or
reduce emissions of United States greenhouse gases could require the Company to
incur increased operating costs, and could have an adverse effect on demand for
oil and natural gas.
The
Company cannot predict how future environmental laws and regulations may impact
its properties or operations. For the year ended December 31,
2009, the Company did not incur any material capital expenditures for
installation of remediation or pollution control equipment at any of the
Company’s facilities. The Company is not aware of any environmental
issues or claims that will require material capital expenditures during 2010 or
that will otherwise have a material impact on its financial position or results
of operations.
Employees
As of
December 31, 2009, the Company employed approximately 550
personnel. None of the employees are represented by labor unions or
covered by any collective bargaining agreement. The Company believes
that its relationship with its employees is satisfactory.
Principal
Executive Offices
The
Company is a Delaware limited liability company with headquarters in
Texas. The principal executive offices are located at 600 Travis,
Suite 5100, Houston, Texas 77002. The main telephone number is (281)
840-4000.
Company
Website
The
Company’s internet website is www.linnenergy.com. The
Company makes available free of charge on or through its website Annual Reports
on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K,
and any
amendments to those reports filed or furnished pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable
after the Company electronically files such material with, or furnishes it to,
the SEC. Information on the Company’s website should not be
considered a part of, or incorporated by reference into, this Annual Report on
Form 10-K.
The SEC
maintains an internet website that contains these reports at www.sec.gov. Any
materials that the Company files with the SEC may be read or copied at the SEC’s
Public Reference Room at 100 F Street, NE, Washington, DC
20549. Information concerning the operation of the Public Reference
Room may be obtained by calling the SEC at (800) 732-0330.
Forward-Looking
Statements
This
Annual Report on Form 10-K contains forward-looking statements that are
subject to a number of risks and uncertainties, many of which are beyond the
Company’s control. These statements may include statements about the
Company’s:
|
|
·
|
business
strategy;
|
|
|
·
|
acquisition
strategy;
|
|
|
·
|
financial
strategy;
|
|
|
·
|
drilling
locations;
|
|
|
·
|
oil,
natural gas and NGL reserves;
|
|
|
·
|
realized
oil, natural gas and NGL prices;
|
|
|
·
|
production
volumes;
|
|
|
·
|
lease
operating expenses, general and administrative expenses and development
costs;
|
|
|
·
|
future
operating results; and
|
|
|
·
|
plans,
objectives, expectations and
intentions.
|
All of
these types of statements, other than statements of historical fact included in
this Annual Report on Form 10-K, are forward-looking
statements. These forward-looking statements may be found in
Item 1. “Business;” Item 1A. “Risk Factors;” Item 7.
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and other items within this Annual Report on
Form 10-K. In some cases, forward-looking statements can be
identified by terminology such as “may,” “will,” “could,” “should,” “expect,”
“plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,”
“potential,” “pursue,” “target,” “continue,” the negative of such terms or other
comparable terminology.
The
forward-looking statements contained in this Annual Report on Form 10-K are
largely based on Company expectations, which reflect estimates and assumptions
made by Company management. These estimates and assumptions reflect
management’s best judgment based on currently known market conditions and other
factors. Although the Company believes such estimates and assumptions
to be reasonable, they are inherently uncertain and involve a number of risks
and uncertainties beyond its control. In addition, management’s
assumptions may prove to be inaccurate. The Company cautions that the
forward-looking statements contained in this Annual Report on Form 10-K are
not guarantees of future performance, and it cannot assure any reader that such
statements will be realized or the forward-looking statements or events will
occur. Actual results may differ materially from those anticipated or
implied in forward-looking statements due to factors listed in the “Risk
Factors” section and elsewhere in this Annual Report on
Form 10-K. The forward-looking statements speak only as of the
date made, and other than as required by law, the Company undertakes no
obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or otherwise.
Our
business has many risks. Factors that could materially adversely
affect our business, financial position, operating results or liquidity and the
trading price of our units are described below. This information
should be considered carefully, together with other information in this report
and other reports and materials we file with the SEC.
We
may not have sufficient cash flow from operations to pay the quarterly
distribution at the current distribution level, or at all, and future
distributions to our unitholders may fluctuate from quarter to
quarter.
We may
not have sufficient cash flow from operations each quarter to pay the quarterly
distribution at the current distribution level. Under the terms of
our limited liability company agreement, the amount of cash otherwise available
for distribution will be reduced by our operating expenses and any cash reserve
amounts that our Board of Directors establishes to provide for future
operations, future capital expenditures, future debt service requirements and
future cash distributions to our unitholders. The amount of cash we
can distribute on our units principally depends upon the amount of cash we
generate from our operations, which will fluctuate from quarter to quarter based
on, among other things:
|
|
·
|
produced
volumes of oil, natural gas and
NGL;
|
|
|
·
|
prices
at which oil, natural gas and NGL production is
sold;
|
|
|
·
|
level
of our operating costs;
|
|
|
·
|
payment
of interest, which depends on the amount of our indebtedness and the
interest payable thereon; and
|
|
|
·
|
level
of our capital expenditures.
|
In
addition, the actual amount of cash we will have available for distribution will
depend on other factors, some of which are beyond our control,
including:
|
|
·
|
availability
of borrowings under our Credit Facility to pay
distributions;
|
|
|
·
|
the
costs of acquisitions, if any;
|
|
|
·
|
fluctuations
in our working capital needs;
|
|
|
·
|
timing
and collectibility of receivables;
|
|
|
·
|
restrictions
on distributions contained in our Credit
Facility;
|
|
|
·
|
prevailing
economic conditions;
|
|
|
·
|
access
to credit or capital markets;
|
|
|
·
|
renegotiation
of our Credit Facility at existing terms and pricing;
and
|
|
|
·
|
the
amount of cash reserves established by our Board of Directors for the
proper conduct of our business.
|
As a
result of these factors, the amount of cash we distribute to our unitholders in
any quarter may fluctuate significantly from quarter to quarter and may be
significantly less than the current distribution level, or the distribution may
be suspended.
We
actively seek to acquire oil and natural gas properties. Acquisitions
involve potential risks that could adversely impact our future growth and our
ability to increase or pay distributions at the current level, or at
all.
Any
acquisition involves potential risks, including, among other
things:
|
|
·
|
the
risk that reserves expected to support the acquired assets may not be of
the anticipated magnitude or may not be developed as
anticipated;
|
|
|
·
|
the
risk of title defects discovered after
closing;
|
|
|
·
|
inaccurate
assumptions about revenues and costs, including
synergies;
|
|
|
·
|
significant
increases in our indebtedness and working capital
requirements;
|
|
|
·
|
an
inability to transition and integrate successfully or timely the
businesses we acquire;
|
|
|
·
|
the
cost of transition and integration of data systems and
processes;
|
|
|
·
|
the
potential environmental problems and
costs;
|
|
|
·
|
the
assumption of unknown liabilities;
|
|
|
·
|
limitations
on rights to indemnity from the
seller;
|
|
|
·
|
the
diversion of management’s attention from other business
concerns;
|
|
|
·
|
increased
demands on existing personnel and on our corporate
structure;
|
|
|
·
|
customer
or key employee losses of the acquired businesses;
and
|
|
|
·
|
the
failure to realize expected growth or
profitability.
|
The scope
and cost of these risks may ultimately be materially greater than estimated at
the time of the acquisition. Further, our future acquisition costs
may be higher than those we have achieved historically. Any of these
factors could adversely impact our future growth and our ability to increase or
pay distributions.
If
we do not make future acquisitions on economically acceptable terms, then our
growth and ability to increase distributions will be limited.
Our
ability to grow and to increase distributions to our unitholders is partially
dependent on our ability to make acquisitions that result in an increase in
available cash flow per unit. We may be unable to make such
acquisitions because we are:
|
|
·
|
unable
to identify attractive acquisition candidates or negotiate acceptable
purchase contracts with them;
|
|
|
·
|
unable
to obtain financing for these acquisitions on economically acceptable
terms; or
|
|
|
·
|
outbid
by competitors.
|
In any
such case, our future growth and ability to increase distributions will be
limited. Furthermore, even if we do make acquisitions that we believe
will increase available cash flow per unit, these acquisitions may nevertheless
result in a decrease in available cash flow per unit.
We
have significant indebtedness under our Credit Facility, 2017 Notes and 2018
Notes (each as defined in Note 6). Our Credit Facility has
substantial restrictions and financial covenants and we may have difficulty
obtaining additional credit, which could adversely affect our operations, our
ability to make acquisitions and our ability to pay distributions to our
unitholders.
We have
significant indebtedness under our Credit Facility, 2017 Notes and 2018
Notes. As of January 29, 2010, we had an aggregate of
approximately $1.7 billion outstanding under our Credit Facility, 2017 Notes and
2018 Notes (with additional borrowing capacity of approximately $422.0
million). As a result of our indebtedness, we will use a portion of
our cash flow to pay interest and principal when due, which will reduce the cash
available to finance our operations and other business activities and could
limit our flexibility in planning for or reacting to changes in our business and
the industry in which we operate.
The
Credit Facility restricts our ability to obtain additional financing, make
investments, lease equipment, sell assets, enter into commodity and interest
rate derivative contracts and engage in business combinations. We
also are required to comply with certain financial covenants and
ratios. Our ability to comply with these restrictions and covenants
in the future is uncertain and will be affected by the levels of cash flow from
our operations and events or circumstances beyond our control. Our
failure to comply with any of the restrictions and covenants could result in an
event of default, which, if it continues beyond any applicable cure periods,
could cause all of our existing indebtedness to be immediately due and
payable.
We depend
on our Credit Facility for future capital needs. We have drawn on our
Credit Facility to fund or partially fund quarterly cash distribution payments,
since we use operating cash flow for drilling and development of oil and natural
gas properties and acquisitions and borrow as cash is needed. Absent
such borrowing, we would have at times experienced a shortfall in cash available
to pay our declared quarterly cash distribution amount. If there is
an event of default by us under our Credit Facility that continues beyond any
applicable cure period, we would be unable to make borrowings to fund
distributions. In addition, we may finance acquisitions through
borrowings under our Credit Facility or the incurrence of additional
debt. To the extent that we are unable to incur additional debt under
our Credit Facility or otherwise because we are not in compliance with the
financial covenants in the Credit Facility, we may not be able to complete
acquisitions, which could adversely affect our ability to maintain or increase
distributions.
Availability
under our Credit Facility is determined semi-annually at the discretion of the
lenders and is based in part on oil, natural gas and NGL
prices. Significant declines in oil, natural gas or NGL prices may
result in a decrease in our borrowing base. The lenders can
unilaterally adjust the borrowing base and the borrowings permitted to be
outstanding under the Credit Facility. Any increase in the borrowing
base requires the consent of all
the
lenders. Outstanding borrowings in excess of the borrowing base must
be repaid immediately, or we must pledge other properties as additional
collateral. We do not currently have any substantial unpledged
properties, and we may not have the financial resources in the future to make
any mandatory principal prepayments required under the Credit
Facility. Significant declines in our production or significant
declines in realized oil, natural gas or NGL prices for prolonged periods and
resulting decreases in our borrowing base may force us to reduce or suspend
distributions to our unitholders.
Our
ability to access the capital and credit markets to raise capital on favorable
terms will be affected by our debt level and by disruptions in the capital and
credit markets, which could adversely affect our operations, our ability to make
acquisitions and our ability to pay distributions to our
unitholders.
The cost
of raising money in the debt and equity capital markets has increased
substantially while the availability of funds from those markets generally has
diminished significantly. Also, as a result of concerns about the
stability of financial markets and the solvency of counterparties specifically,
the cost of obtaining money from the credit markets generally has increased as
some major financial institutions have consolidated and others may consolidate
in the future, some lenders may increase interest rates, enact tighter lending
standards, refuse to refinance existing debt at maturity on favorable terms or
at all and may reduce or cease to provide funding to borrowers. If we
are unable to refinance our Credit Facility on terms that are as favorable as
those in our existing Credit Facility, or at all, our ability to fund our
operations and our ability to pay distributions could be affected.
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 and we are unable to
effectively hedge our interest rate risk, 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.
Increases
in interest rates could adversely affect the demand for our units.
An
increase in interest rates may cause a corresponding decline in demand for
equity investments, in particular for yield-based equity investments such as our
units. Any such reduction in demand for our units resulting from
other more attractive investment opportunities may cause the trading price of
our units to decline.
Our
commodity derivative activities could result in financial losses or could reduce
our income, which may adversely affect our ability to pay distributions to our
unitholders.
To
achieve more predictable cash flow and to reduce our exposure to adverse
fluctuations in the prices of oil, natural gas and NGL, we enter into commodity
derivative contracts for a significant portion of our
production. Commodity derivative arrangements expose us to the risk
of financial loss in some circumstances, including situations when the other
party to the contract defaults on its contract or production is less than
expected. If we experience a sustained material interruption in our
production or if we are unable to perform our drilling activity as planned, we
might be forced to satisfy all or a portion of our derivative obligations
without the benefit of the cash flow from our sale of the underlying physical
commodity, resulting in a substantial reduction of our liquidity, which may
adversely affect our ability to pay distributions to our
unitholders.
Disruptions
in the capital and credit markets may adversely affect our derivative
positions.
We cannot
be assured that our counterparties will be able to perform under our derivative
contracts. If a counterparty fails to perform and the derivative
arrangement is terminated, our cash flow and ability to pay distributions could
be impacted.
Commodity
prices are volatile, and a significant decline in commodity prices for a
prolonged period would reduce our revenues, cash flow from operations and
profitability and we may have to lower our distribution or may not be able to
pay distributions at all.
Our
revenue, profitability and cash flow depend upon the prices of and demand for
oil, natural gas and NGL. The oil, natural gas and NGL market is very
volatile and a drop in prices can significantly affect our financial results and
impede our growth. Changes in oil, natural gas and NGL prices have a
significant impact on the value of our reserves and on our cash
flow. Prices for these commodities may fluctuate widely in response
to relatively minor changes in the supply of and demand for them, market
uncertainty and a variety of additional factors that are beyond our control,
such as:
|
|
·
|
the
domestic and foreign supply of and demand for oil, natural gas and
NGL;
|
|
|
·
|
the
price and level of foreign imports;
|
|
|
·
|
the
level of consumer product demand;
|
|
|
·
|
weather
conditions;
|
|
|
·
|
overall
domestic and global economic
conditions;
|
|
|
·
|
political
and economic conditions in oil and natural gas producing countries,
including those in the Middle East and South
America;
|
|
|
·
|
the
ability of members of the Organization of Petroleum Exporting Countries to
agree to and maintain price and production
controls;
|
|
|
·
|
the
impact of the United States dollar exchange rates on oil, natural gas and
NGL prices;
|
|
|
·
|
technological
advances affecting energy
consumption;
|
|
|
·
|
domestic
and foreign governmental regulations and
taxation;
|
|
|
·
|
the
impact of energy conservation
efforts;
|
|
|
·
|
the
proximity and capacity of pipelines and other transportation facilities;
and
|
|
|
·
|
the
price and availability of alternative
fuels.
|
In the
past, the prices of oil, natural gas and NGL have been extremely volatile, and
we expect this volatility to continue. If commodity prices decline
significantly for a prolonged period, our cash flow from operations will
decline, and we may have to lower our distribution or may not be able to pay
distributions at all.
Future price
declines or downward reserve revisions may result in a write down of our asset
carrying values, which could
adversely affect our results of operations and limit our ability to borrow
funds.
Declines
in oil, natural gas and NGL prices may result in our having to make substantial
downward adjustments to our estimated proved reserves. If this
occurs, or if our estimates of development costs increase, production data
factors change or drilling results deteriorate, accounting rules may require us
to write down, as a noncash charge to earnings, the carrying value of our
properties for impairments. We capitalize costs to acquire, find and
develop our oil and natural gas properties under the successful efforts
accounting method. We are required to perform impairment tests on our
assets periodically and whenever events or changes in circumstances warrant a
review of our assets. To the extent such tests indicate a reduction
of the estimated useful life or estimated future cash flows of our assets, the
carrying value may not be recoverable and therefore would require a write
down. We may incur impairment charges in the future, which could have
a material adverse effect on our results of operations in the period incurred
and on our ability to borrow funds under our Credit Facility, which in turn may
adversely affect our ability to make cash distributions to our
unitholders.
Unless
we replace our reserves, our reserves and production will decline, which would
adversely affect our cash flow from operations and our ability to make
distributions to our unitholders.
Producing
oil, natural gas and NGL reservoirs are characterized by declining production
rates that vary depending upon reservoir characteristics and other
factors. The overall rate of decline for our production will change
if production from our existing wells declines in a different manner than we
have estimated and can change when we drill additional wells, make acquisitions
and under other circumstances. Thus, our future oil, natural gas and
NGL
reserves
and production and, therefore, our cash flow and income, are highly dependent on
our success in efficiently developing our current reserves and economically
finding or acquiring additional recoverable reserves. We may not be
able to develop, find or acquire additional reserves to replace our current and
future production at acceptable costs, which would adversely affect our cash
flow from operations and our ability to make distributions to our
unitholders.
Our
estimated reserves are based on many assumptions that may prove to be
inaccurate. Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and present value
of our reserves.
No one
can measure underground accumulations of oil, natural gas and NGL in an exact
way. Reserve engineering requires subjective estimates of underground
accumulations of oil, natural gas and NGL and assumptions concerning future oil,
natural gas and NGL prices, production levels and operating and development
costs. As a result, estimated quantities of proved reserves and
projections of future production rates and the timing of development
expenditures may prove to be inaccurate. Independent petroleum
engineering firms prepare estimates of our proved reserves. Some of
our reserve estimates are made without the benefit of a lengthy production
history, which are less reliable than estimates based on a lengthy production
history. Also, we make certain assumptions regarding future oil,
natural gas and NGL prices, production levels and operating and development
costs that may prove incorrect. Any significant variance from these
assumptions by actual figures could greatly affect our estimates of reserves,
the economically recoverable quantities of oil, natural gas and NGL attributable
to any particular group of properties, the classifications of reserves based on
risk of recovery and estimates of the future net cash flows. Numerous
changes over time to the assumptions on which our reserve estimates are based,
as described above, often result in the actual quantities of oil, natural gas
and NGL we ultimately recover being different from our reserve
estimates.
The
present value of future net cash flows from our proved reserves is not
necessarily the same as the current market value of our estimated oil, natural
gas and NGL reserves. We base the estimated discounted future net
cash flows from our proved reserves on an unweighted average of the
first-day-of-the month price for each month during the 12-month calendar year
and year-end costs. However, actual future net cash flows from our
oil and natural gas properties also will be affected by factors such
as:
|
|
·
|
actual
prices we receive for oil, natural gas and
NGL;
|
|
|
·
|
the
amount and timing of actual
production;
|
|
|
·
|
the
timing and success of development
activities;
|
|
|
·
|
supply
of and demand for oil, natural gas and NGL;
and
|
|
|
·
|
changes
in governmental regulations or
taxation.
|
In
addition, the 10% discount factor, required to be used under the provisions of
applicable accounting standards when calculating discounted future net cash
flows, may not be the most appropriate discount factor based on interest rates
in effect from time to time and risks associated with us or the oil and natural
gas industry in general.
Our
development operations require substantial capital expenditures, which will
reduce our cash available for distribution. We may be unable to
obtain needed capital or financing on satisfactory terms, which could lead to a
decline in our reserves.
The oil
and natural gas industry is capital intensive. We make and expect to
continue to make substantial capital expenditures in our business for the
development, production and acquisition of oil, natural gas and NGL
reserves. These expenditures will reduce our cash available for
distribution. We intend to finance our future capital expenditures
with cash flow from operations and our financing arrangements. Our
cash flow from operations and access to capital are subject to a number of
variables, including:
|
|
·
|
our
proved reserves;
|
|
|
·
|
the
level of oil, natural gas and NGL we are able to produce from existing
wells;
|
|
|
·
|
the
prices at which we are able to sell our oil, natural gas and NGL;
and
|
|
|
·
|
our
ability to acquire, locate and produce new
reserves.
|
If our
revenues or the borrowing base under our Credit Facility decrease as a result of
lower oil, natural gas and NGL prices, operating difficulties, declines in
reserves or for any other reason, we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. Our
Credit Facility restricts our ability to obtain new financing. If
additional capital is needed, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. If cash generated by
operations or available under our Credit Facility is not sufficient to meet our
capital requirements, the failure to obtain additional financing could result in
a curtailment of our development operations, which in turn could lead to a
possible decline in our reserves.
We
may decide not to drill some of the prospects we have identified, and locations
that we decide to drill may not yield oil, natural gas and NGL in commercially
viable quantities.
Our
prospective drilling locations are in various stages of evaluation, ranging from
a prospect that is ready to drill to a prospect that will require additional
geological and engineering analysis. Based on a variety of factors,
including future oil, natural gas and NGL prices, the generation of additional
seismic or geological information, the availability of drilling rigs and other
factors, we may decide not to drill one or more of these
prospects. As a result, we may not be able to increase or maintain
our reserves or production, which in turn could have an adverse effect on our
business, financial position or results of operations. In addition,
the SEC’s reserve reporting rules include a general requirement that, subject to
limited exceptions, proved undeveloped reserves may only be booked if they
relate to wells scheduled to be drilled within five years of the date of
booking. At December 31, 2009, we had 1,241 proved undeveloped
drilling locations. To the extent that we do not drill these
prospects within five years of initial booking, they may not continue to qualify
for classification as proved reserves, and we may be required to reclassify such
reserves as unproved reserves. The reclassification of such reserves
could also have a negative effect on the borrowing base under our Credit
Facility.
The cost
of drilling, completing and operating a well is often uncertain, and cost
factors can adversely affect the economics of a well. Our efforts
will be uneconomic if we drill dry holes or wells that are productive but do not
produce enough oil, natural gas and NGL to be commercially viable after
drilling, operating and other costs. If we drill future wells that we
identify as dry holes, our drilling success rate would decline, which could have
an adverse effect on our business, financial position or results of
operations.
Our
business depends on gathering and transportation facilities. Any
limitation in the availability of those facilities would interfere with our
ability to market the oil, natural gas and NGL we produce, and could reduce our
cash available for distribution and adversely impact expected increases in oil,
natural gas and NGL production from our drilling program.
The
marketability of our oil, natural gas and NGL production depends in part on the
availability, proximity and capacity of gathering and pipeline
systems. The amount of oil, natural gas and NGL that can be produced
and sold is subject to limitation in certain circumstances, such as pipeline
interruptions due to scheduled and unscheduled maintenance, excessive pressure,
physical damage to the gathering or transportation system, or lack of contracted
capacity on such systems. The curtailments arising from these and
similar circumstances may last from a few days to several months. In
many cases, we are provided only with limited, if any, notice as to when these
circumstances will arise and their duration. In addition, some of our
wells are drilled in locations that are not serviced by gathering and
transportation pipelines, or the gathering and transportation pipelines in the
area may not have sufficient capacity to transport additional
production. As a result, we may not be able to sell the oil, natural
gas and NGL production from these wells until the necessary gathering and
transportation systems are constructed. Any significant curtailment
in gathering system or pipeline capacity, or significant delay in the
construction of necessary gathering and transportation facilities, would
interfere with our ability to market the oil, natural gas and NGL we produce,
and could reduce our cash available for distribution and adversely impact
expected increases in oil, natural gas and NGL production from our drilling
program.
We depend on certain key customers
for sales of our oil, natural gas and NGL. To the extent these and
other customers reduce the volumes they purchase from us or delay payment, our
revenues and cash available for distribution could decline. Further,
a general increase in nonpayment could have an adverse impact on our financial
position and results of operations.
For the
year ended December 31, 2009, DCP Midstream Partners, LP, Enbridge Energy
Partners, L.P. and ConocoPhillips accounted for approximately 25%, 19% and 12%,
respectively, of our total volumes, or 56% in the aggregate. For the
year ended December 31, 2008, DCP Midstream Partners, LP, ConocoPhillips
and Enbridge Energy Partners, L.P. accounted for approximately 23%, 12% and 11%,
respectively, of our total volumes from continuing operations, or 46% in the
aggregate. To the extent these and other customers reduce the volumes
of oil, natural gas or NGL that they purchase from us, our revenues and cash
available for distribution could decline.
Many
of our leases are in areas that have been partially depleted or drained by
offset wells.
Our key
project areas are located in some of the most active drilling areas of the
producing basins in the United States. As a result, many of our
leases are in areas that have already been partially depleted or drained by
earlier offset drilling. This may inhibit our ability to find
economically recoverable quantities of reserves in these areas.
Our
identified drilling location inventories are scheduled out over several years,
making them susceptible to uncertainties that could materially alter the
occurrence or timing of their drilling, resulting in temporarily lower cash from
operations, which may impact our ability to pay distributions.
Our
management has specifically identified and scheduled drilling locations as an
estimation of our future multi-year drilling activities on our existing
acreage. As of December 31, 2009, we had identified 4,291
drilling locations, of which 1,241 were proved undeveloped locations and 3,050
were other locations. These identified drilling locations represent a
significant part of our growth strategy. Our ability to drill and
develop these locations depends on a number of factors, including the
availability of capital, seasonal conditions, regulatory approvals, oil, natural
gas and NGL prices, costs and drilling results. In addition, DeGolyer
and MacNaughton has not estimated proved reserves for the 3,050 other drilling
locations we have identified and scheduled for drilling, and therefore there may
be greater uncertainty with respect to the success of drilling wells at these
drilling locations. Our final determination on whether to drill any
of these drilling locations will be dependent upon the factors described above
as well as, to some degree, the results of our drilling activities with respect
to our proved drilling locations. Because of these uncertainties, we
do not know if the numerous drilling locations we have identified will be
drilled within our expected timeframe or will ever be drilled or if we will be
able to produce oil, natural gas and NGL from these or any other potential
drilling locations. As such, our actual drilling activities may
materially differ from those presently identified, which could adversely affect
our business.
Drilling
for and producing oil, natural gas and NGL are high risk activities with many
uncertainties that could adversely affect our financial position or results of
operations and, as a result, our ability to pay distributions to our
unitholders.
Our
drilling activities are subject to many risks, including the risk that we will
not discover commercially productive reservoirs. Drilling for oil,
natural gas and NGL can be uneconomic, not only from dry holes, but also from
productive wells that do not produce sufficient revenues to be commercially
viable. In addition, our drilling and producing operations may be
curtailed, delayed or canceled as a result of other factors,
including:
|
|
·
|
the
high cost, shortages or delivery delays of equipment and
services;
|
|
|
·
|
unexpected
operational events;
|
|
|
·
|
adverse
weather conditions;
|
|
|
·
|
facility
or equipment malfunctions;
|
|
|
·
|
title
problems;
|
|
|
·
|
pipeline
ruptures or spills;
|
|
|
·
|
compliance
with environmental and other governmental
requirements;
|
|
|
·
|
unusual
or unexpected geological
formations;
|
|
|
·
|
loss
of drilling fluid circulation;
|
|
|
·
|
formations
with abnormal pressures;
|
|
|
·
|
fires;
|
|
|
·
|
blowouts,
craterings and explosions; and
|
|
|
·
|
uncontrollable
flows of oil, natural gas and NGL or well
fluids.
|
Any of
these events can cause increased costs or restrict our ability to drill the
wells and conduct the operations which we currently have planned. Any
delay in the drilling program or significant increase in costs could impact our
ability to generate sufficient cash flow to pay quarterly distributions to our
unitholders at the current distribution level. Increased costs could
include losses from personal injury or loss of life, damage to or destruction of
property, natural resources and equipment, pollution, environmental
contamination, loss of wells and regulatory penalties. We ordinarily
maintain insurance against certain losses and liabilities arising from our
operations. However, it is impossible to insure against all
operational risks in the course of our business. Additionally, we may
elect not to obtain insurance if we believe that the cost of available insurance
is excessive relative to the perceived risks presented. Losses could
therefore occur for uninsurable or uninsured risks or in amounts in excess of
existing insurance coverage. The occurrence of an event that is not
fully covered by insurance could have a material adverse impact on our business
activities, financial position and results of operations.
Because
we handle oil, natural gas and NGL and other hydrocarbons, we may incur
significant costs and liabilities in the future resulting from a failure to
comply with new or existing environmental regulations or an accidental release
of hazardous substances into the environment.
The
operations of our wells, gathering systems, turbines, pipelines and other
facilities are subject to stringent and complex federal, state and local
environmental laws and regulations. These include, for
example:
|
|
·
|
the
federal Clean Air Act and comparable state laws and regulations that
impose obligations related to air
emissions;
|
|
|
·
|
the
federal Clean Water Act and comparable state laws and regulations that
impose obligations related to discharges of pollutants into regulated
bodies of water;
|
|
|
·
|
the
federal Resource Conservation and Recovery Act (“RCRA”), and comparable
state laws that impose requirements for the handling and disposal of waste
from our facilities; and
|
|
|
·
|
the
Comprehensive Environmental Response, Compensation and Liability Act of
1980 (“CERCLA”), also known as “Superfund,” and comparable state laws that
regulate the cleanup of hazardous substances that may have been released
at properties currently or previously owned or operated by us or at
locations to which we have sent waste for
disposal.
|
Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain
environmental statutes, including the RCRA, CERCLA and analogous state laws and
regulations, impose strict, joint and several liability for costs required to
clean up and restore sites where hazardous substances have been disposed of or
otherwise released. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the release of hazardous substances or other
waste products into the environment.
There is
an inherent risk that we may incur environmental costs and liabilities due to
the nature of our business and the substances we handle. For example,
an accidental release from one of our wells or gathering pipelines could subject
us to substantial liabilities arising from environmental cleanup and restoration
costs, claims made by neighboring landowners and other third parties for
personal injury and property damage and fines or penalties for related
violations of environmental laws or regulations.
Moreover,
the possibility exists that stricter laws, regulations or enforcement policies
could significantly increase our compliance costs and the cost of any
remediation that may become necessary, and these costs may not be
recoverable
from insurance. For a more detailed discussion of environmental and
regulatory matters impacting our business, see Item 1. “Business -
Environmental Matters and Regulation.”
We
are subject to complex federal, state, local and other laws and regulations that
could adversely affect the cost, manner or feasibility of doing
business.
Our
operations are regulated extensively at the federal, state and local
levels. Environmental and other governmental laws and regulations
have increased the costs to plan, design, drill, install, operate and abandon
oil and natural gas wells. Under these laws and regulations, we could
also be liable for personal injuries, property damage and other
damages. Failure to comply with these laws and regulations may result
in the suspension or termination of our operations and subject us to
administrative, civil and criminal penalties. Moreover, public
interest in environmental protection has increased in recent years, and
environmental organizations have opposed, with some success, certain drilling
projects.
Part of
the regulatory environment in which we operate includes, in some cases, legal
requirements for obtaining environmental assessments, environmental impact
studies and/or plans of development before commencing drilling and production
activities. In addition, our activities are subject to the
regulations regarding conservation practices and protection of correlative
rights. These regulations affect our operations and limit the
quantity of oil, natural gas and NGL we may produce and sell. A major
risk inherent in our drilling plans is the need to obtain drilling permits from
state and local authorities. Delays in obtaining regulatory approvals
or drilling permits, the failure to obtain a drilling permit for a well or the
receipt of a permit with unreasonable conditions or costs could have a material
adverse effect on our ability to develop our
properties. Additionally, the regulatory environment could change in
ways that might substantially increase the financial and managerial costs of
compliance with these laws and regulations and, consequently, adversely affect
our ability to pay distributions to our unitholders. For a
description of the laws and regulations that affect us, see Item 1.
“Business - Environmental Matters and Regulation.”
We
may issue additional units without unitholder approval, which would dilute
existing ownership interests.
We may
issue an unlimited number of limited liability company interests of any type,
including units, without the approval of our unitholders.
The
issuance of additional units or other equity securities may have the following
effects:
|
|
·
|
an
individual unitholder’s proportionate ownership interest in us may
decrease;
|
|
|
·
|
the
relative voting strength of each previously outstanding unit may be
reduced;
|
|
|
·
|
the
amount of cash available for distribution per unit may decrease;
and
|
|
|
·
|
the
market price of the units may
decline.
|
Our
management may have conflicts of interest with the unitholders. Our
limited liability company agreement limits the remedies available to our
unitholders in the event unitholders have a claim relating to conflicts of
interest.
Conflicts
of interest may arise between our management on one hand, and the Company and
our unitholders on the other hand, related to the divergent interests of our
management. Situations in which the interests of
our management may differ from interests of our nonaffiliated
unitholders include, among others, the following situations:
|
|
·
|
our
limited liability company agreement gives our Board of Directors broad
discretion in establishing cash reserves for the proper conduct of our
business, which will affect the amount of cash available for
distribution. For example, our management will use its
reasonable discretion to establish and maintain cash reserves sufficient
to fund our drilling program;
|
|
|
·
|
our
management team, subject to oversight from our Board of Directors,
determines the timing and extent of our drilling program and related
capital expenditures, asset purchases and sales, borrowings, issuances
of
|
additional
membership interests and reserve adjustments, all of which will affect the
amount of cash that we distribute to our unitholders; and
|
|
·
|
affiliates
of our directors are not prohibited from investing or engaging in other
businesses or activities that compete with the
Company.
|
We
do not have the same flexibility as other types of organizations to accumulate
cash and equity to protect against illiquidity in the future.
Unlike a
corporation, our limited liability company agreement requires us to make
quarterly distributions to our unitholders of all available cash reduced by any
amounts of reserves for commitments and contingencies, including capital and
operating costs and debt service requirements. The value of our units
may decrease in direct correlation with decreases in the amount we distribute
per unit. Accordingly, if we experience a liquidity problem in the
future, we may have difficulty issuing more equity to recapitalize.
Our
tax treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to a material amount of entity-level
taxation by individual states. If the Internal Revenue Service
(“IRS”) were to treat us as a corporation for federal income tax purposes or we
were to become subject to entity-level taxation for state tax purposes, taxes
paid, if any, would reduce the amount of cash available for
distribution.
The
anticipated after-tax economic benefit of an investment in our units depends
largely on our being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling
from the IRS on this or any other tax matter that affects us.
If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our taxable income at the corporate tax rates, currently
at a maximum rate of 35%. Distributions would generally be taxed
again as corporate distributions, and no income, gain, loss, deduction or credit
would flow through to unitholders. Because a tax may be imposed on us
as a corporation, our cash available for distribution to our unitholders could
be reduced. Therefore, treatment of us as a corporation would result
in a material reduction in the anticipated cash flow and after-tax return to our
unitholders, likely causing a substantial reduction in the value of our
units.
Current
law or our business may change so as to cause us to be treated as a corporation
for federal income tax purposes or otherwise subject us to entity-level
taxation. Any modification to current
law or interpretations thereof may or may not be applied retroactively and could
make it more difficult or impossible to meet the requirements for partnership
status, affect or cause us to change our business activities, affect the tax
considerations of an investment in us, change the character or treatment of
portions of our income and adversely affect an investment in our
units.
In
addition, because of widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships and limited liability
companies to entity-level taxation through the imposition of state income,
franchise or other forms of taxation. For example, we are required to
pay Texas franchise tax at a maximum effective rate of 0.7% of our total revenue
apportioned to Texas in the prior year. Imposition of a tax on us by
any other state would reduce the amount of cash available for distribution to
our unitholders.
A
successful IRS contest of the federal income tax positions we take may adversely
affect the market for our units, and the cost of an IRS contest will reduce our
cash available for distribution to our unitholders.
The IRS may adopt tax positions that differ from the
positions we take. It may be necessary to resort to administrative or
court proceedings to sustain some or all of the positions we take. A
court may not agree with some or all of the positions we take. Any
contest with the IRS may materially and adversely impact the market for our
units and the price at which they trade. In addition, the costs of
any contest with the IRS will be borne indirectly by our unitholders because the
costs will reduce our cash available for distribution.
Unitholders
are required to pay taxes on their share of our taxable income, including their
share of ordinary income and capital gain upon dispositions of properties by us,
even if they do not receive any cash distributions from us. A
unitholder’s share of our taxable income, gain, loss and deduction, or specific
items thereof, may be substantially different than the unitholder’s interest in
our economic profits.
Our
unitholders are required to pay federal income taxes and, in some cases, state
and local income taxes on their share of our taxable income, whether or not they
receive cash distributions from us. Our unitholders may not receive
cash distributions from us equal to their share of our taxable income or even
equal to the actual tax liability that results from their share of our taxable
income. For example, we may sell a portion of our properties and use
the proceeds to pay down debt or acquire other properties rather than
distributing the proceeds to our unitholders, and some or all of our unitholders
may be allocated substantial taxable income with respect to that
sale.
A
unitholder’s share of our taxable income upon a disposition of property by us
may be ordinary income or capital gain or some combination
thereof. Even where we dispose of properties that are capital assets,
what otherwise would be capital gains may be recharacterized as ordinary income
in order to “recapture” ordinary deductions that were previously allocated to
that unitholder related to the same property.
A
unitholder’s share of our taxable income and gain (or specific items thereof)
may be substantially greater than, or our tax losses and deductions (or specific
items thereof) may be substantially less than, the unitholder’s interest in our
economic profits. This may occur, for example, in the case of a
unitholder who purchases units at a time when the value of our units or of one
or more of our properties is relatively low or a unitholder who acquires units
directly from us in exchange for property whose fair market value exceeds its
tax basis at the time of the exchange.
A
unitholder’s taxable gain or loss on the disposition of our units could be more
or less than expected.
If
unitholders sell their units, they will recognize a gain or loss equal to the
difference between the amount realized and their tax basis in those
units. Prior distributions to our unitholders in excess of the total
net taxable income they were allocated for a unit, which decreases their tax
basis, will become taxable income to our unitholders if the unit is sold at a
price greater than their tax basis in that unit, even if the price received is
less than their original cost.
A
substantial portion of the amount realized, whether or not representing gain,
may be ordinary income. In addition, if unitholders sell their units,
they may incur a tax liability in excess of the amount of cash they receive from
the sale. If the IRS successfully contests some positions we take,
unitholders could recognize more gain on the sale of units than would be the
case under those positions, without the benefit of decreased income in prior
years.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning our units that
may result in adverse tax consequences to them.
Investment
in units by tax-exempt entities, such as individual retirement accounts (known
as IRAs) and other retirement plans, and non-U.S. persons raises issues unique
to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable
to them. Distributions to non-U.S. persons will be reduced by
withholding taxes at the highest applicable effective tax rate, and non-U.S.
persons will be required to file United States federal tax returns and pay tax
on their share of our taxable income.
We
treat each purchaser of units as having the same tax benefits without regard to
the units purchased. The IRS may challenge this treatment, which
could adversely affect the value of the units.
Because
we cannot match transferors and transferees of units, we must maintain
uniformity of the economic and tax characteristics of our units to a purchaser
of units. We take depletion, depreciation and amortization positions
that are intended to maintain such uniformity. These depletion,
depreciation and amortization positions may not conform with all aspects of
existing Treasury regulations. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to our
unitholders. It also could affect the timing of these
tax
benefits
or the amount of gain from unitholders’ sale of units and could have a negative
impact on the value of our units or result in audit adjustments to unitholder
tax returns.
The
sale or exchange of 50% or more of our capital and profits interests within a
twelve-month period will result in the deemed termination of our tax partnership
for federal income tax purposes.
We will
be considered to have terminated for federal income tax purposes if there is a
sale or exchange of 50% or more of the total interests in our capital and
profits within a twelve-month period. Our termination would, among
other things, result in the closing of our taxable year for all unitholders and
could result in a deferral of depreciation deductions allowable in computing our
taxable income. If this occurs, our unitholders will be allocated an
increased amount of federal taxable income for the year in which we are
considered to be terminated as a percentage of the cash distributed to the
unitholders with respect to that period.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month (or in some cases for periods shorter than a
month) based upon the ownership of our units on the first day of each month (or
shorter period), instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could change
the allocation of items of income, gain, loss and deduction among our
unitholders.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month (or in some cases for periods shorter than a
month) based
upon the ownership of our units on the first day of each month (or shorter
period), instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be permitted
under existing Treasury regulations. If the IRS were to challenge
this method or new Treasury regulations were issued, we may be required to
change the allocation of items of income, gain, loss and deduction among our
unitholders.
A
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of those units. If so, the
unitholder would no longer be treated for tax purposes as a partner with respect
to those units during the period of the loan and may recognize gain or loss from
the disposition.
Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, the unitholder
may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may
recognize gain or loss from such disposition. Moreover, during the
period of the loan to the short seller, any of our income, gain, loss, or
deduction with respect to those units may not be reportable by the unitholder
and any cash distributions received by the unitholder as to those units could be
fully taxable as ordinary income. Unitholders desiring to assure
their status as partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage account agreements to
prohibit their brokers from borrowing their units.
Unitholders
may be subject to state and local taxes and return filing requirements in states
and jurisdictions where they do not live as a result of investing in our
units.
In
addition to federal income taxes, our unitholders will likely be subject to
other taxes, including state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property now or in the future, even
if they do not reside in any of those jurisdictions. Our unitholders
will likely be required to file foreign, state and local income tax returns and
pay state and local income taxes in some or all of these
jurisdictions. Further, our unitholders may be subject to penalties
for failure to comply with those requirements. In 2009, we have done
business and owned assets in West Virginia, Virginia, Pennsylvania, California,
Oklahoma, Kansas, New Mexico, Illinois, Indiana, Arkansas, Colorado, Kentucky,
Louisiana, Mississippi, Montana, North Dakota, South Dakota and
Texas. As we make acquisitions or expand our business, we may do
business or own assets in other states in the future. It is the
responsibility of each unitholder to file all United States federal, state and
local tax returns that may be required of such unitholder.
Changes
to current federal tax laws may affect unitholders’ ability to take certain tax
deductions.
Substantive
changes to the existing federal income tax laws have been proposed that, if
adopted, would affect, among other things, the ability to take certain
operations-related deductions, including deductions for intangible drilling and
percentage depletion and deductions for United States production
activities. Other proposed changes may affect our ability to remain
taxable as a partnership for federal income tax purposes. We are
unable to predict whether any changes, or other proposals to such laws,
ultimately will be enacted. Any such changes could negatively impact
the value of an investment in our units.
The
adoption of derivatives legislation by the United States Congress could have an
adverse impact on our ability to hedge risks associated with our
business.
Several
proposals for derivative reform have been developed by committees in the United
States House of Representatives and the United States Senate. These
proposals are focused on expanding federal regulation surrounding the use of
financial derivative instruments, including credit default swaps, commodity
derivatives and other over-the-counter derivatives. Among the
recommendations included in the proposals are the requirements for centralized
clearing or settling of such derivatives as well as the expansion of collateral
margin requirements for certain derivative-market
participants. Depending on the ultimate form of legislation, our
derivatives utilization could be adversely affected with: (i) greater
administrative burden; (ii) limitations on the form and use of derivatives; and
(iii) expanded collateral margin requirements.
Although
it is not possible at this time to predict when the United States Congress may
act on derivatives legislation, any laws or regulations that may be adopted that
subject us to additional restrictions on our commodity derivative positions
could have an adverse effect on our ability to hedge.
None.
Information
concerning proved reserves, production, wells, acreage and related matters are
contained in Item 1. “Business.”
The
Company’s obligations under its Credit Facility are secured by mortgages on its
oil and natural gas properties. See Item 7. “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and
Note 6 for additional information concerning the Credit
Facility.
Offices
The
Company’s principal corporate office is located at 600 Travis, Suite 5100,
Houston, Texas 77002. The Company maintains additional offices in
California, Illinois, Kansas, Louisiana, Oklahoma and Texas.
Although
the Company may, from time to time, be involved in litigation and claims arising
out of its operations in the normal course of business, the Company is not
currently a party to any material legal proceedings. In addition, the
Company is not aware of any material legal or governmental proceedings against
it, or contemplated to be brought against it, under the various environmental
protection statutes to which it is subject.
There
were no matters submitted to a vote of security holders during the three months
ended December 31, 2009.
Executive
Officers of the Company
|
Name
|
Age
|
Position
with the Company
|
||
|
Michael
C. Linn
|
58
|
Executive
Chairman of the Board of Directors
|
||
|
Mark
E. Ellis
|
54
|
President
and Chief Executive Officer and Director
|
||
|
Kolja
Rockov
|
39
|
Executive
Vice President and Chief Financial Officer
|
||
|
Charlene
A. Ripley
|
46
|
Senior
Vice President, General Counsel and Corporate Secretary
|
||
|
David
B. Rottino
|
44
|
Senior
Vice President and Chief Accounting Officer
|
||
|
Arden
L. Walker, Jr.
|
50
|
Senior
Vice President and Chief Operating
Officer
|
Michael C. Linn is the
Executive Chairman of the Board of Directors of the Company and has served in
such capacity since January 2010. He served as Chairman and Chief
Executive Officer from December 2007 to January 2010; Chairman, President and
Chief Executive Officer from June 2006 to December 2007; and President, Chief
Executive Officer and Director of the Company from March 2003 to June
2006. Mr. Linn serves on the National Petroleum Council and
American Exploration and Production Council. He serves on the boards
of America’s Natural Gas Alliance and the Independent Petroleum Association of
America (“IPAA”). He is also Chairman of the IPAA Political Action
Committee and past Chairman of IPAA. He serves as the Texas
Representative for the Legal and Regulatory Affairs Committee of the Interstate
Oil and Gas Compact Commission. He previously served as Chairman of
the National Gas Council and Director of the Natural Gas Supply
Association. He is former President of the Independent Oil and Gas
Associations of New York, Pennsylvania and West
Virginia. Mr. Linn regularly appears on behalf of the oil and
natural gas industry before state and federal agencies, United States Congress
and national broadcast media. His civic affiliations include serving
on the boards of the Texas Heart Institute, Museum of Fine Arts Houston and
Houston Police Foundation. In addition, he is the Chairman of the
Texas Children’s Hospital Corporate Committee Capital Campaign. He
also serves on the Advisory Board of Houston Children’s Charity and is a member
of the Dean’s Executive Advisory Board for the University of Houston C.T. Bauer
College of Business. Mr. Linn graduated cum laude from Villanova
University in 1974 with a BA in Political Science cum laude from the University
of Baltimore School of Law in 1977. Following graduation,
Mr. Linn went on to practice law for the law firm of Ecker, Ecker, Zofer
and Rome. In 1980, he became General Counsel for Meridian
Exploration, where he ultimately served as President and Chief Executive Officer
until its sale in 1999. He served as President of Allegheny
Interests, Inc. from 2000 to 2003.
Mark E. Ellis is the
President and Chief Executive Officer and a Director of the Company and has
served in such capacity since January 2010. From December 2007 to
January 2010, Mr. Ellis served as President and Chief Operating Officer and from
December 2006 to December 2007, Mr. Ellis served as Executive Vice
President and Chief Operating Officer of the Company. Mr. Ellis
has more than 30 years of experience in the oil and natural gas industry, most
recently serving as President, Lower 48 for ConocoPhillips from April 2006 to
November 2006. Prior to joining ConocoPhillips, Mr. Ellis served
as Senior Vice President of North American Production for Burlington Resources
from September 2004 to April 2006. He served as President of
Burlington Resources Canada Ltd. in Calgary from October 2000 to September
2004. Mr. Ellis joined Burlington Resources in 1985 and also
held the positions of Vice President of the San Juan Division, Vice President
and Chief Engineer and Manager of Acquisitions. He began his career
at The Superior Oil Company, where he served in several engineering positions in
the Onshore and Offshore divisions. Mr. Ellis is a member of the
Society of Petroleum Engineers, a past board member of the New Mexico Oil &
Gas Association and previously served on the Board of Governors of the Canadian
Association of Petroleum Producers and served on the Foundation Board of the
Alberta Children’s Hospital. Mr. Ellis currently serves on the
Board of The Center for Hearing and Speech in Houston, Houston Museum of Natural
Science, the Cynthia Woods Mitchell Pavilion, Industry Board of Petroleum
Engineering at Texas A&M University and the Visiting Committee of Petroleum
Engineering at the Colorado School of Mines.
Kolja Rockov is the Executive
Vice President and Chief Financial Officer. Mr. Rockov has more
than 15 years of experience in the oil and natural gas finance
industry. From October 2004 until he joined LINN Energy in March
2005, Mr. Rockov served as a Managing Director in the Energy Group at RBC
Capital Markets, where he was primarily responsible for investment banking
coverage of the United States exploration and production
sector. Prior
to
October 2004, Mr. Rockov held various senior positions with RBC Capital
Markets and its predecessor companies.
Charlene A. Ripley is
the Senior Vice President, General Counsel and Corporate Secretary and has
served in that position since April 2007. Prior to joining the
Company, Ms. Ripley held the position of Vice President, General Counsel,
Corporate Secretary and Chief Compliance Officer at Anadarko Petroleum
Corporation from 2006 until April 2007 and served as Vice President, General
Counsel and Corporate Secretary from 2004 until 2006. Ms. Ripley
served as Vice President, General Counsel and Secretary of Anadarko Canada
Corporation and its predecessor companies since 1998.
David B. Rottino is the
Senior Vice President and Chief Accounting Officer and has served in that
position since June 2008. Mr. Rottino’s career includes more
than 15 years of oil and natural gas accounting experience, most recently
serving as Vice President and E&P Controller for El Paso Corporation from
June 2006 to May 2008. Prior to joining El Paso Corporation,
Mr. Rottino served as Assistant Controller for ConocoPhillips from April
2006 to June 2006. He was Vice President and Chief Financial Officer
for the Canadian division of Burlington Resources from July 2005 to April 2006
and served as Burlington Resources’ Director of Financial Analysis and Corporate
Accounting from August 2000 to July 2005. Mr. Rottino joined
Burlington Resources in 1996 and has served in a broad range of accounting and
audit positions. Mr. Rottino is a Certified Public Accountant
and a member of the American Institute of Certified Public Accountants and Texas
Society of Certified Public Accountants. In addition, he currently
serves on the Board of the June Rusche Hamrah Camp For All.
Arden L. Walker, Jr. is
the Senior Vice President and Chief Operating Officer of the Company and has
served in such capacity since January 2010. Mr. Walker joined
the Company in February 2007 as Senior Vice President - Operations and
Chief Engineer to oversee its Texas, Oklahoma and California operations, and he
is currently responsible for oversight of the Company’s operations in all
regions. In addition, Mr. Walker serves in the capacity of chief
engineer for the Company and is responsible for the Company’s reserve review and
booking processes. From April 2006 until he joined the Company in
February 2007, Mr. Walker served as Asset Development Manager, San Juan
Business Unit for ConocoPhillips Company. From June 2004 to April
2006, Mr. Walker served as General Manager, Asset Development in San Juan
Division for Burlington Resources. Mr. Walker began his career
with El Paso Exploration Company in 1982 and has served in a broad range of
engineering, business development and management positions with Burlington
Resources since that time. Mr. Walker is a member of the Society
of Petroleum Engineers, Independent Petroleum Association of America and
California Independent Petroleum Association.
28
Market
Information
The
Company’s units are listed on The NASDAQ Global Select Market (“NASDAQ”) under
the symbol “LINE” and began trading on January 13, 2006, after pricing of
its initial public offering. At the close of business on
January 29, 2010, there were approximately 372 unitholders of
record.
The
following sets forth the range of high and low last reported sales prices per
unit, as reported by NASDAQ, for the quarters indicated. In addition,
distributions declared during each quarter are presented.
|
Unit
Price Range
|
Cash
Distribution
Declared
|
|||||||||||
|
Quarter
|
High
|
Low
|
Per
Unit
|
|||||||||
|
2009:
|
||||||||||||
|
October
1 – December 31
|
$ | 28.00 | $ | 22.18 | $ | 0.63 | ||||||
|
July
1 – September 30
|
$ | 23.96 | $ | 18.66 | $ | 0.63 | ||||||
|
April
1 – June 30
|
$ | 20.42 | $ | 14.77 | $ | 0.63 | ||||||
|
January
1 – March 31
|
$ | 16.65 | $ | 12.95 | $ | 0.63 | ||||||
|
2008:
|
||||||||||||
|
October
1 – December 31
|
$ | 17.03 | $ | 11.20 | $ | 0.63 | ||||||
|
July
1 – September 30
|
$ | 24.88 | $ | 14.93 | $ | 0.63 | ||||||
|
April
1 – June 30
|
$ | 25.57 | $ | 19.44 | $ | 0.63 | ||||||
|
January
1 – March 31
|
$ | 24.41 | $ | 18.88 | $ | 0.63 | ||||||
Distributions
The
Company’s limited liability company agreement requires it to make quarterly
distributions to unitholders of all “available cash.”
Available
cash means, for each fiscal quarter, all cash on hand at the end of the quarter
less the amount of cash reserves established by the Board of Directors
to:
|
|
·
|
provide
for the proper conduct of business (including reserves for future capital
expenditures, future debt service requirements, and for anticipated credit
needs); and
|
|
|
·
|
comply
with applicable laws, debt instruments or other
agreements;
|
plus all
cash on hand on the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of the quarter for
which the determination is being made.
Working
capital borrowings are borrowings that will be made under the Company’s Credit
Facility and in all cases are used solely for working capital purposes or to pay
distributions to unitholders.
See
Item 7. “Management’s Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources” for a discussion
on the payment of future distributions.
29
| Item 5. |
Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities -
Continued
|
Unitholder
Return Performance Presentation
The
performance graph below compares the total unitholder return on the Company’s
units, with the total return of the Standard & Poor’s 500 Index (the
“S&P 500 Index”) and the Alerian MLP Index, a weighted composite of 50
prominent energy master limited partnerships. Total return includes
the change in the market price, adjusted for reinvested dividends or
distributions, for the period shown on the performance graph and assumes that
$100 was invested in the Company at the last reported sale price of units as
reported by NASDAQ ($22.00) on January 13, 2006, (the date trading of the
units commenced) and in the S&P 500 Index and the Alerian MLP Index on the
same date. The results shown in the graph below are not necessarily
indicative of future performance.
|
January
13, 2006
|
December 31,
2006
|
December 31,
2007
|
December 31,
2008
|
December 31,
2009
|
||||||||||||||||
|
LINN
Energy
|
$ | 100 | $ | 153 | $ | 128 | $ | 87 | $ | 185 | ||||||||||
|
Alerian
MLP Index
|
$ | 100 | $ | 120 | $ | 136 | $ | 86 | $ | 151 | ||||||||||
|
S&P
500 Index
|
$ | 100 | $ | 112 | $ | 118 | $ | 75 | $ | 94 | ||||||||||
Notwithstanding
anything to the contrary set forth in any of the Company’s previous or future
filings under the Securities Act of 1933 or the Securities Exchange Act of 1934
that might incorporate this Annual Report on Form 10-K or future filings
with the SEC, in whole or in part, the preceding performance information shall
not be deemed to be “soliciting material” or to be “filed” with the SEC or
incorporated by reference into any filing except to the extent this performance
presentation is specifically incorporated by reference therein.
Securities
Authorized for Issuance Under Equity Compensation Plans
See the
information incorporated by reference under Item 12. “Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder Matters”
regarding securities authorized for issuance under the Company’s equity
compensation plans, which information is incorporated by reference into this
Item 5.
30
| Item 5. |
Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities -
Continued
|
Sales
of Unregistered Securities
None.
Issuer
Purchases of Equity Securities
In
October 2008, the Board of Directors of the Company authorized the repurchase of
up to $100.0 million of the Company’s outstanding units from time to time on the
open market or in negotiated purchases. The repurchase plan does not
obligate the Company to acquire any specific number of units and may be
discontinued at any time. The Company did not repurchase any units
during the three months ended December 31, 2009. At
December 31, 2009, approximately $85.4 million was available for unit
repurchase under the program.
The
selected financial data set forth below should be read in conjunction with
Item 7. “Management’s Discussion and Analysis of Financial Condition and
Results of Operations” and Item 8. “Financial Statements and Supplementary
Data.”
Because
of rapid growth through acquisitions and development of properties, the
Company’s historical results of operations and period-to-period comparisons of
these results and certain other financial data may not be meaningful or
indicative of future results. The results of the Company’s
Appalachian Basin and Mid Atlantic operations are classified as discontinued
operations for all periods presented (see Note 2). Unless
otherwise indicated, results of operations information presented herein relates
only to continuing operations.
|
At
or for the Year Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||||||||||
|
Statement
of operations data:
|
||||||||||||||||||||
|
Oil,
natural gas and natural gas liquid sales
|
$ | 408,219 | $ | 755,644 | $ | 255,927 | $ | 21,372 | $ | ― | ||||||||||
|
Gain
(loss) on oil and natural gas derivatives
|
(141,374 | ) | 662,782 | (345,537 | ) | 103,308 | (76,193 | ) | ||||||||||||
|
Depreciation,
depletion and amortization
|
201,782 | 194,093 | 69,081 | 4,352 | ― | |||||||||||||||
|
Interest
expense, net of amounts capitalized
|
92,701 | 94,517 | 38,974 | 5,909 | 481 | |||||||||||||||
|
Income
(loss) from continuing operations
|
(295,841 | ) | 825,657 | (356,194 | ) | 69,811 | (79,311 | ) | ||||||||||||
|
Income
(loss) from discontinued operations, net of taxes (1)
|
(2,351 | ) | 173,959 | (8,155 | ) | 9,374 | 22,960 | |||||||||||||
|
Net
income (loss)
|
(298,192 | ) | 999,616 | (364,349 | ) | 79,185 | (56,351 | ) | ||||||||||||
|
Income
(loss) per unit – continuing operations: (2)
|
||||||||||||||||||||
|
Basic
|
(2.48 | ) | 7.18 | (5.17 | ) | 2.30 | (3.87 | ) | ||||||||||||
|
Diluted
|
(2.48 | ) | 7.18 | (5.17 | ) | 2.28 | (3.87 | ) | ||||||||||||
|
Income
(loss) per unit – discontinued operations: (2)
|
||||||||||||||||||||
|
Basic
|
(0.02 | ) | 1.52 | (0.12 | ) | 0.31 | 1.12 | |||||||||||||
|
Diluted
|
(0.02 | ) | 1.52 | (0.12 | ) | 0.31 | 1.12 | |||||||||||||
|
Net
income (loss) per unit: (2)
|
||||||||||||||||||||
|
Basic
|
(2.50 | ) | 8.70 | (5.29 | ) | 2.61 | (2.75 | ) | ||||||||||||
|
Diluted
|
(2.50 | ) | 8.70 | (5.29 | ) | 2.59 | (2.75 | ) | ||||||||||||
|
Distributions
declared per unit
|
2.52 | 2.52 | 2.18 | 1.15 | ― | |||||||||||||||
|
Weighted
average units outstanding
|
119,307 | 114,140 | 68,916 | 28,281 | 20,518 | |||||||||||||||
|
Cash
flow data:
|
||||||||||||||||||||
|
Net
cash provided by (used in):
|
||||||||||||||||||||
|
Operating
activities (3)
|
$ | 426,804 | $ | 179,515 | $ | (44,814 | ) | $ | (6,805 | ) | $ | (29,518 | ) | |||||||
|
Investing
activities
|
(282,273 | ) | (35,550 | ) | (2,892,420 | ) | (551,631 | ) | (150,898 | ) | ||||||||||
|
Financing
activities
|
(150,968 | ) | (116,738 | ) | 2,932,080 | 553,990 | 189,269 | |||||||||||||
|
Balance
sheet data:
|
||||||||||||||||||||
|
Total
assets
|
$ | 4,340,256 | $ | 4,722,020 | $ | 3,807,703 | $ | 905,912 | $ | 280,924 | ||||||||||
|
Long-term
debt
|
1,588,831 | 1,653,568 | 1,443,830 | 428,237 | 207,695 | |||||||||||||||
|
Unitholders’
capital (deficit)
|
2,452,004 | 2,760,686 | 2,026,641 | 450,954 | (46,831 | ) | ||||||||||||||
|
(1)
|
Includes
gain (loss) on sale of assets, net of
taxes.
|
|
(2)
|
Effective
January 1, 2009, the Company adopted an accounting standard requiring
unvested restricted units to be included in the computation of earnings
per unit under the two-class method. The adoption required
retrospective adjustment of all prior period earnings per unit
data. The impact of the adoption was a reduction to income from
continuing operations per unit – diluted and net income per
unit – diluted, of $0.05 per unit and $0.02 per unit for the years
ended December 31, 2008, and December 31, 2006,
respectively. There was no impact for the years ended
December 31, 2007, or December 31,
2005.
|
|
(3)
|
Includes
premiums paid for derivatives of approximately $93.6 million, $129.5
million, $279.3 million, $49.8 million and $1.6 million for the years
ended December 31, 2009, December 31, 2008, December 31,
2007, December 31, 2006, and December 31, 2005,
respectively.
|
|
At
or for the Year Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Production
data:
|
||||||||||||||||||||
|
Average
daily production – continuing operations:
|
||||||||||||||||||||
|
Natural
gas (MMcf/d)
|
125 | 124 | 51 | 2 | ― | |||||||||||||||
|
Oil
(MBbls/d)
|
9.0 | 8.6 | 3.4 | 0.9 | ― | |||||||||||||||
|
NGL
(MBbls/d)
|
6.5 | 6.2 | 2.7 | ― | ― | |||||||||||||||
|
Total
(MMcfe/d)
|
218 | 212 | 87 | 8 | ― | |||||||||||||||
|
Average
daily production – discontinued operations:
|
||||||||||||||||||||
|
Total
(MMcfe/d)
|
― | 12 | 24 | 22 | 13 | |||||||||||||||
|
Estimated proved reserves –
continuing operations: (1)
|
||||||||||||||||||||
|
Natural
gas (Bcf)
|
774 | 851 | 833 | 77 | ― | |||||||||||||||
|
Oil
(MMBbls)
|
102 | 84 | 55 | 30 | ― | |||||||||||||||
|
NGL
(MMBbls)
|
54 | 51 | 43 | ― | ― | |||||||||||||||
|
Total
(Bcfe)
|
1,712 | 1,660 | 1,419 | 255 | ― | |||||||||||||||
|
Estimated proved reserves –
discontinued operations: (1)
|
||||||||||||||||||||
|
Total
(Bcfe)
|
― | ― | 197 | 199 | 193 | |||||||||||||||
|
(1)
|
In
accordance with SEC regulations, reserves at December 31, 2009, were
estimated using the average price during the 12-month period, determined
as an unweighted average of the first-day-of-the-month price for each
month, unless prices are defined by contractual arrangements, excluding
escalations based upon future conditions. In accordance with
SEC regulations, reserves for all prior years were estimated using
year-end prices.
|
33
The
following discussion and analysis should be read in conjunction with the
“Consolidated Financial Statements” and “Notes to Consolidated Financial
Statements,” which are included in this Annual Report on Form 10-K in
Item 8. “Financial Statements and Supplementary Data.” The
following discussion contains forward-looking statements that reflect the
Company’s future plans, estimates, beliefs and expected
performance. The forward-looking statements are dependent upon
events, risks and uncertainties that may be outside the Company’s
control. The Company’s actual results could differ materially from
those discussed in these forward-looking statements. Factors that
could cause or contribute to such differences include, but are not limited to,
market prices for oil, natural gas and NGL, production volumes, estimates of
proved reserves, capital expenditures, economic and competitive conditions,
credit and capital market conditions, regulatory changes and other
uncertainties, as well as those factors discussed below and elsewhere in this
Annual Report on Form 10-K, particularly in Item 1A. “Risk
Factors.” In light of these risks, uncertainties and assumptions, the
forward-looking events discussed may not occur.
A
reference to a “Note” herein refers to the accompanying Notes to Consolidated
Financial Statements contained in Item 8. “Financial Statements and
Supplementary Data.”
Executive
Overview
LINN
Energy’s mission is to acquire, develop and maximize cash flow from a growing
portfolio of long-life oil and natural gas assets. LINN Energy is an
independent oil and natural gas company that began operations in March 2003 and
completed its IPO in January 2006. The Company’s properties are
located in the United States, primarily in the Mid-Continent, California and the
Permian Basin.
Proved
reserves at December 31, 2009, were 1,712 Bcfe, of which approximately 36%
were oil, 45% were natural gas and 19% were NGL. Approximately 71%
were classified as proved developed, with a total standardized measure of
discounted future net cash flows of $1.72 billion. At
December 31, 2009, the Company operated 4,688, or 68%, of its 6,931gross
productive wells and had an average proved reserve-life index of approximately
22 years, based on the December 31, 2009, reserve report and annualized
production for the three months ended December 31, 2009.
In
January 2010, the Company completed an acquisition of oil and natural gas
properties in the Anadarko and Permian Basins for a contract price of $154.5
million. See “Acquisitions” below for additional
details. On a pro forma basis, including this acquisition, total
proved reserves at December 31, 2009, were 1,785 Bcfe, of which
approximately 37% were oil, 44% were natural gas and 19% were
NGL. For additional information regarding estimates of reserves, see
“Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial
Statements and Supplementary Data” and see also Item 1. “Business.”
From
inception through the date of this report, excluding 15 acquisitions comprising
the Appalachian Basin properties sold in July 2008, the Company has completed 13
acquisitions of working and royalty interests in oil and natural gas properties
and related gathering and pipeline assets. Total acquired proved
reserves were approximately 1.8 Tcfe at the time of acquisition at an
acquisition cost of approximately $2.15 per Mcfe. The Company
finances acquisitions with a combination of funds from equity and debt
offerings, bank borrowings and cash generated from operations. See
Note 2 for additional details about the Company’s acquisitions and
divestitures.
The
results of the Company’s Appalachian Basin and Mid Atlantic operations are
classified as discontinued operations for all periods
presented. Unless otherwise indicated, results of operations
information presented herein relates only to continuing operations.
Results
from continuing operations for the year ended December 31, 2009, included
the following:
|
|
·
|
oil,
natural gas and NGL sales of approximately $408.2 million, compared to
$755.6 million in 2008;
|
|
|
·
|
average
daily production of 218 MMcfe/d, compared to 212 MMcfe/d in
2008;
|
34
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
|
|
·
|
realized
gains on commodity derivatives of approximately $450.0 million, compared
to realized losses of $72.0 million in
2008;
|
|
|
·
|
adjusted
EBITDA of $566.2 million, compared to $514.5 million in
2008;
|
|
|
·
|
adjusted
net income of $206.9 million, compared to $174.7 million in
2008;
|
|
|
·
|
capital
expenditures, excluding acquisitions, of approximately $149.5 million,
compared to $321.3 million in 2008;
and
|
|
|
·
|
73 wells
drilled (72 successful), compared to 306 wells drilled (304 successful) in
2008.
|
Adjusted
EBITDA and adjusted net income are non-GAAP financial measures used by
management to analyze Company performance. Adjusted EBITDA is a
measure used by Company management to evaluate cash flow and the Company’s
ability to sustain or increase distributions. The most significant
reconciling items between net income (loss) and adjusted EBITDA are interest
expense and noncash items, including the change in fair value of derivatives and
depreciation, depletion and amortization. Adjusted net income is used
by Company management to evaluate its operational performance from oil and
natural gas properties, prior to derivative gains and losses, impairment of
goodwill and long-lived assets and (gain) loss on sale of assets, net. See “Non-GAAP
Financial Measures” on page 56 for a reconciliation of each non-GAAP
financial measure to its most directly comparable financial measure calculated
and presented in accordance with GAAP.
Acquisitions
On
January 29, 2010, the Company completed the acquisition of certain oil and
natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and
the Permian Basin in Texas and New Mexico, from Merit for a contract price of
$154.5 million. The transaction was financed with borrowings under
the Company’s Credit Facility. The acquisition provides a strategic
addition to the Company’s asset portfolio in the Permian Basin and
Mid-Continent, and includes approximately 12 MMBoe (73 Bcfe) of proved reserves
as of the acquisition date, primarily oil.
On
August 31, 2009, and September 30, 2009, the Company completed the
acquisitions of certain oil and natural gas properties located in the Permian
Basin in Texas and New Mexico from Forest. The Company paid $114.4
million in cash, net of cash received from Forest post-closing, and recorded a
receivable from Forest, resulting in total consideration for the acquisitions of
approximately $113.7 million. The transactions were financed with
borrowings under the Company’s Credit Facility. The acquisitions
represent a strategic entry into the Permian Basin for the Company, and include
approximately 10 MMBoe (62 Bcfe) of proved reserves, primarily oil.
Commodity
Derivatives
In
February 2010, the Company entered into fixed price oil swaps on an additional
5,250 Bbls per day at a price of $100.00 per Bbl for the years ending
December 31, 2012, and December 31, 2013, bringing the Company’s total
such fixed price oil swaps to swaps on 7,250 Bbls per day as presented in the
table below. The Company has derivative contracts that extend the
swaps for each of the years ending December 31, 2014, December 31,
2015, and December 31, 2016, if the counterparties determine that the
strike prices are in-the-money on a designated date in each respective preceding
year. The extension for each year is exercisable without respect to
the other years.
35
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
The
following table summarizes open positions as of February 24, 2010, and
represents, as of such date, derivatives in place through December 31,
2013, on annual production volumes:
|
February
24 –
December
31,
2010
|
Year
2011
|
Year
2012
|
Year
2013
|
|||||||||||||
|
Natural
gas positions:
|
||||||||||||||||
|
Fixed
price swaps:
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
32,971 | 31,901 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 8.90 | $ | 9.50 | $ | — | $ | — | ||||||||
|
Puts:
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
5,800 | 6,960 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 8.50 | $ | 9.50 | $ | — | $ | — | ||||||||
|
PEPL
puts: (1)
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
8,862 | 13,259 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 7.85 | $ | 8.50 | $ | — | $ | — | ||||||||
|
Total:
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
47,633 | 52,120 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 8.66 | $ | 9.25 | $ | — | $ | — | ||||||||
|
Oil
positions:
|
||||||||||||||||
|
Fixed
price swaps: (2)
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
1,971 | 2,073 | 2,654 | 2,646 | ||||||||||||
|
Average
price ($/Bbl)
|
$ | 90.00 | $ | 90.00 | $ | 100.00 | $ | 100.00 | ||||||||
|
Puts:
(3)
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
2,062 | 2,352 | — | — | ||||||||||||
|
Average
price ($/Bbl)
|
$ | 110.00 | $ | 75.00 | $ | — | $ | — | ||||||||
|
Collars:
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
229 | 276 | — | — | ||||||||||||
|
Average
floor price ($/Bbl)
|
$ | 90.00 | $ | 90.00 | $ | — | $ | — | ||||||||
|
Average
ceiling price ($/Bbl)
|
$ | 112.00 | $ | 112.25 | $ | — | $ | — | ||||||||
|
Total:
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
4,262 | 4,701 | 2,654 | 2,646 | ||||||||||||
|
Average
price ($/Bbl)
|
$ | 99.68 | $ | 82.50 | $ | 100.00 | $ | 100.00 | ||||||||
|
Natural
gas basis differential positions:
|
||||||||||||||||
|
PEPL
basis swaps: (1)
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
35,972 | 35,541 | 34,066 | 31,700 | ||||||||||||
|
Hedged
differential ($/MMBtu)
|
$ | (0.97 | ) | $ | (0.96 | ) | $ | (0.95 | ) | $ | (1.01 | ) | ||||
|
(1)
|
Settle
on the PEPL spot price of natural gas to hedge basis differential
associated with natural gas production in the Mid-Continent Deep and
Mid-Continent Shallow regions.
|
|
(2)
|
As
presented in the table above, the Company has outstanding fixed price oil
swaps on 7,250 Bbls per day at a price of $100.00 per Bbl for the years
ending December 31, 2012, and December 31, 2013. The
Company has derivative contracts that extend the swaps for each of the
years ending December 31, 2014, December 31, 2015, and
December 31, 2016, if the counterparties determine that the strike
prices are in-the-money on a designated date in each respective preceding
year. The extension for each year is exercisable without
respect to the other years.
|
|
(3)
|
The
Company utilizes oil puts to hedge revenues associated with its NGL
production.
|
36
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Liquidity
and Debt
During
2009, the Company took several steps to strengthen its liquidity and extend its
weighted average debt maturities. In April 2009, the Company amended
and restated its existing Credit Facility to extend the maturity to August 2012,
and at January 29, 2010, the Company had $422.0 million in available
borrowing capacity under the Credit Facility. In addition, in May
2009, the Company issued $250.0 million in aggregate principal of 11.75% senior
notes due 2017 and used the net proceeds of approximately $230.8 million to
reduce indebtedness under its Credit Facility. In May 2009 and
October 2009, the Company completed public offerings of units for aggregate net
proceeds of approximately $279.3 million, which was used to reduce indebtedness
under the Credit Facility.
The
Company hedges a significant portion of its forecasted production to reduce
exposure to fluctuations in the prices of oil, natural gas and NGL and provide
long-term cash flow predictability to pay distributions, service debt and manage
its business. By removing a significant portion of the price
volatility associated with future production, the Company expects to mitigate,
but not eliminate, the potential effects of variability in cash flow from
operations due to fluctuations in commodity prices. The Company has
derivative contracts in place for 2010 and 2011 at average prices of $99.68 per
Bbl and $82.50 per Bbl for oil and $8.66 per MMBtu and $9.25 per MMBtu for
natural gas, respectively. Additionally, the Company has derivative
contracts in place covering substantially all of its exposure to the
Mid-Continent natural gas basis differential.
Operating
Regions
Inclusive
of the properties acquired from Merit in January 2010 (see “Acquisitions”
above), the Company’s properties are located in four regions in the United
States:
|
|
·
|
Mid-Continent
Deep, which includes the Texas Panhandle Deep Granite Wash formation and
deep formations in Oklahoma and
Kansas;
|
|
|
·
|
Mid-Continent
Shallow, which includes the Texas Panhandle Brown Dolomite formation and
shallow formations in Oklahoma, Louisiana and
Illinois;
|
|
|
·
|
California,
which includes the Brea Olinda Field of the Los Angeles Basin;
and
|
|
|
·
|
Permian
Basin, which includes areas in West Texas and Southeast New
Mexico.
|
Mid-Continent
Deep
The
Mid-Continent Deep region includes properties in the Deep Granite Wash formation
in the Texas Panhandle, which produces at depths ranging from 8,900 feet to
16,000 feet, as well as properties in Oklahoma and Kansas , which produce at
depths of more than 8,000 feet. Mid-Continent Deep proved
reserves represented approximately 47% of total proved reserves at
December 31, 2009, of which 71% were classified as proved developed
reserves. This region produced 135 MMcfe/d, or 62%, of the Company’s
2009 average daily production. During 2009, the Company invested
approximately $99.3 million to drill in this region. During 2010, the
Company anticipates spending approximately 60% of its total capital budget for
development activities in the Mid-Continent Deep region.
Mid-Continent
Shallow
The
Mid-Continent Shallow region includes properties producing from the Brown
Dolomite formation in the Texas Panhandle, which produces at depths of
approximately 3,200 feet and properties in Oklahoma, Louisiana and Illinois,
which produce at depths of less than 8,000 feet. Mid-Continent
Shallow proved reserves represented approximately 38% of total proved reserves
at December 31, 2009, of which 66% were classified as proved developed
reserves. This region produced 67 MMcfe/d, or 31%, of the Company’s
2009 average daily production. During 2009, the Company invested
approximately $21.0 million to drill in this region. During 2010, the
Company anticipates spending approximately 20% of its total capital budget for
development activities in the Mid-Continent Shallow region.
37
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
To more
efficiently transport its natural gas in the Mid-Continent Deep and
Mid-Continent Shallow regions to market, the Company owns and operates a network
of natural gas gathering systems comprised of approximately 900 miles of
pipeline and associated compression and metering facilities that connect to
numerous sales outlets in the Texas Panhandle.
California
The
California region consists of the Brea Olinda Field of the Los Angeles
Basin. The Brea Olinda Field was discovered in 1880 and produces from
the shallow Pliocene formation to the deeper Miocene formation at depths of
1,000 feet to 7,500 feet. California proved reserves represented
approximately 11% of total proved reserves at December 31, 2009, of which
94% were classified as proved developed reserves. This region
produced 14 MMcfe/d, or 6%, of the Company’s 2009 average daily
production.
Permian
Basin
The
Permian Basin is one of the largest and most prolific oil and natural gas basins
in the United States. The Company’s properties are located in West
Texas and Southeast New Mexico and produce at depths ranging from 2,000 feet to
9,000 feet. Permian Basin proved reserves represented approximately
4% of total proved reserves at December 31, 2009, of which 53% were
classified as proved developed reserves. The properties that comprise
this region as of December 31, 2009, were acquired in the third quarter of 2009
(see “Acquisitions” above). This region produced 2 MMcfe/d, or 1%, of
the Company’s 2009 average daily production. During 2009, the Company
invested approximately $0.1 million to drill in this region. During
2010, the Company anticipates spending approximately 20% of its total capital
budget for development activities in the Permian Basin region.
38
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Results
of Operations – Continuing Operations
Year
Ended December 31, 2009, Compared to Year Ended December 31,
2008
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
and other:
|
||||||||||||
|
Natural
gas sales
|
$ | 160,470 | $ | 334,214 | $ | (173,744 | ) | |||||
|
Oil
sales
|
181,619 | 291,132 | (109,513 | ) | ||||||||
|
NGL
sales
|
66,130 | 130,298 | (64,168 | ) | ||||||||
|
Total
oil, natural gas and NGL sales
|
408,219 | 755,644 | (347,425 | ) | ||||||||
|
Gain
(loss) on oil and natural gas derivatives (1)
|
(141,374 | ) | 662,782 | (804,156 | ) | |||||||
|
Natural
gas marketing revenues
|
4,380 | 12,846 | (8,466 | ) | ||||||||
|
Other
revenues
|
1,924 | 3,759 | (1,835 | ) | ||||||||
| $ | 273,149 | $ | 1,435,031 | $ | (1,161,882 | ) | ||||||
|
Expenses:
|
||||||||||||
|
Lease
operating expenses
|
$ | 132,647 | $ | 115,402 | $ | 17,245 | ||||||
|
Transportation
expenses
|
18,202 | 17,597 | 605 | |||||||||
|
Natural
gas marketing expenses
|
2,154 | 11,070 | (8,916 | ) | ||||||||
|
General
and administrative expenses (2)
|
86,134 | 77,391 | 8,743 | |||||||||
|
Exploration
costs
|
7,169 | 7,603 | (434 | ) | ||||||||
|
Bad
debt expenses
|
401 | 1,436 | (1,035 | ) | ||||||||
|
Depreciation,
depletion and amortization
|
201,782 | 194,093 | 7,689 | |||||||||
|
Impairment
of goodwill and long-lived assets
|
— | 50,505 | (50,505 | ) | ||||||||
|
Taxes,
other than income taxes
|
27,605 | 61,435 | (33,830 | ) | ||||||||
|
(Gain)
loss on sale of assets and other, net
|
(24,598 | ) | (98,763 | ) | 74,165 | |||||||
| $ | 451,496 | $ | 437,769 | $ | 13,727 | |||||||
|
Other
income and (expenses)
|
$ | (121,715 | ) | $ | (168,893 | ) | $ | 47,178 | ||||
|
Income
(loss) from continuing operations before income taxes
|
$ | (300,062 | ) | $ | 828,369 | $ | (1,128,431 | ) | ||||
|
Adjusted EBITDA (3)
|
$ | 566,235 | $ | 514,487 | $ | 51,748 | ||||||
|
Adjusted net income
(3)
|
$ | 206,922 | $ | 174,663 | $ | 32,259 | ||||||
|
(1)
|
During
the year ended December 31, 2009, the Company canceled (before the
contract settlement date) derivative contracts on estimated future oil and
natural gas production resulting in realized net gains of approximately
$49.0 million, primarily associated with the Company’s commodity
derivative repositioning in July 2009 (see Note 7). During
the year ended December 31, 2008, the Company canceled (before the
contract settlement date) derivative contracts on estimated future natural
gas production primarily associated with properties in the Appalachian
Basin and Verden areas (see Note 2) resulting in realized losses of
approximately $81.4 million.
|
|
(2)
|
General
and administrative expenses for the years ended December 31, 2009,
and December 31, 2008, include approximately $14.7 million and $14.6
million, respectively, of noncash unit-based compensation
expenses.
|
|
(3)
|
This
is a non-GAAP measure used by management to analyze Company
performance. See “Non-GAAP Financial Measures” on page 56
for a reconciliation of the non-GAAP financial measure to its most
directly comparable financial measure calculated and presented in
accordance with GAAP.
|
39
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
Variance
|
||||||||||
|
Average
daily production:
|
||||||||||||
|
Natural
gas (MMcf/d)
|
125 | 124 | 1 | % | ||||||||
|
Oil
(MBbls/d)
|
9.0 | 8.6 | 5 | % | ||||||||
|
NGL
(MBbls/d)
|
6.5 | 6.2 | 5 | % | ||||||||
|
Total
(MMcfe/d)
|
218 | 212 | 3 | % | ||||||||
|
Weighted average prices
(hedged): (1)
|
||||||||||||
|
Natural
gas (Mcf)
|
$ | 8.27 | $ | 8.42 | (2 | )% | ||||||
|
Oil
(Bbl)
|
$ | 110.94 | $ | 80.92 | 37 | % | ||||||
|
NGL
(Bbl)
|
$ | 28.04 | $ | 57.86 | (52 | )% | ||||||
|
Weighted average prices
(unhedged): (2)
|
||||||||||||
|
Natural
gas (Mcf)
|
$ | 3.51 | $ | 7.39 | (53 | )% | ||||||
|
Oil
(Bbl)
|
$ | 55.25 | $ | 92.78 | (40 | )% | ||||||
|
NGL
(Bbl)
|
$ | 28.04 | $ | 57.86 | (52 | )% | ||||||
|
Average
NYMEX prices:
|
||||||||||||
|
Natural
gas (MMBtu)
|
$ | 3.99 | $ | 9.04 | (56 | )% | ||||||
|
Oil
(Bbl)
|
$ | 61.94 | $ | 99.65 | (38 | )% | ||||||
|
Costs
per Mcfe of production:
|
||||||||||||
|
Lease
operating expenses
|
$ | 1.67 | $ | 1.49 | 12 | % | ||||||
|
Transportation
expenses
|
$ | 0.23 | $ | 0.23 | — | |||||||
|
General
and administrative expenses (3)
|
$ | 1.08 | $ | 1.00 | 8 | % | ||||||
|
Depreciation,
depletion and amortization
|
$ | 2.53 | $ | 2.50 | 1 | % | ||||||
|
Taxes,
other than income taxes
|
$ | 0.35 | $ | 0.79 | (56 | )% | ||||||
|
(1)
|
Includes
the effect of realized gains on derivatives of approximately $401.0
million (excluding $49.0 million realized net gains on canceled contracts)
and $9.4 million (excluding $81.4 million realized losses on canceled
contracts) for the years ended December 31, 2009, and
December 31, 2008, respectively. The Company utilizes oil
puts to hedge revenues associated with its NGL production; therefore, all
realized gains (losses) on oil derivative contracts are included in
weighted average oil prices, rather than weighted average NGL
prices.
|
|
(2)
|
Does
not include the effect of realized gains (losses) on
derivatives.
|
|
(3)
|
General
and administrative expenses for the years ended December 31, 2009,
and December 31, 2008, include approximately $14.7 million and $14.6
million, respectively, of noncash unit-based compensation
expenses. Excluding these amounts, general and administrative
expenses for the years ended December 31, 2009, and December 31,
2008, were $0.90 per Mcfe and $0.81 per Mcfe,
respectively. This is a non-GAAP measure used by management to
analyze the Company’s performance.
|
40
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Revenues
and Other
Oil,
Natural Gas and NGL Sales
Oil,
natural gas and NGL sales decreased by approximately $347.4 million, or
46%, to approximately $408.2 million for the year ended December 31, 2009,
from $755.6 million for the year ended December 31, 2008, due to lower
commodity prices. Lower oil, natural gas and NGL prices resulted in a
decrease in revenues of approximately $123.3, $177.6 million and $70.3 million,
respectively.
Average
daily production increased to 218 MMcfe/d during the year ended
December 31, 2009, from 212 MMcfe/d during the year ended December 31,
2008. Volume increases during the year ended December 31, 2009,
resulted in an increase in total oil, natural gas and NGL revenues of
approximately $23.8 million compared to the year ended December 31,
2008.
The
following sets forth average daily production by region:
|
Year
Ended
December 31,
|
||||||||||||||||
|
2009
|
2008
|
Variance
|
||||||||||||||
|
Average
daily production (MMcfe/d):
|
||||||||||||||||
|
Mid-Continent
Deep
|
135 | 136 | (1 | ) | (1 | )% | ||||||||||
|
Mid-Continent
Shallow
|
67 | 63 | 4 | 6 | % | |||||||||||
|
California
|
14 | 13 | 1 | 8 | % | |||||||||||
|
Permian
Basin
|
2 | — | 2 | — | ||||||||||||
| 218 | 212 | 6 | 3 | % | ||||||||||||
The 1%
decrease in average daily production in the Mid-Continent Deep region primarily
reflects the Company’s sale of assets in Oklahoma in August 2008 (see
Note 2), its decision to suspend completions on recent wells drilled in the
Granite Wash and shut-in production on certain wells. The 6% increase
in average daily production in the Mid-Continent Shallow region reflects results
of the Company’s drilling and optimization programs, partially offset by natural
declines. The California region consists of a low-decline asset base
and continues to produce at levels consistent with the prior
year. The Permian Basin properties were acquired in the third quarter
of 2009 (see Note 2).
Gain
(Loss) on Oil and Natural Gas Derivatives
The
Company determines the fair value of its oil and natural gas derivatives
utilizing pricing models that use a variety of techniques, including market
quotes and pricing analysis. See Item 7A. “Quantitative and
Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for
additional information about commodity derivatives. During the year
ended December 31, 2009, the Company had commodity derivative contracts for
approximately 113% of its natural gas production and 80% of its oil and NGL
production, which resulted in realized gains of approximately $450.0 million
(including realized net gains on canceled contracts of approximately $49.0
million). During the year ended December 31, 2009, the Company
repositioned its commodity derivative portfolio to help protect against
sustained weakness in commodity prices. The Company canceled oil and
natural gas derivative contracts for years 2012 through 2014 and used the
realized net gains of approximately $44.8 million, along with an incremental
premium payment of approximately $48.8 million, to raise prices for oil and
natural gas derivative contracts in years 2010 and 2011. During the
year ended December 31, 2008, the Company recorded realized losses of
approximately $72.0 million (including realized losses on canceled contracts of
approximately $81.4 million). Unrealized gains and losses result from
changes in market valuations of derivatives as future commodity price
expectations change compared to the contract prices on the
derivatives. During 2009, expected future oil and natural gas prices
increased, which resulted in unrealized losses on derivatives of approximately
$591.4 million for the year ended December 31, 2009. During the
second half of 2008, expected future oil and natural gas prices decreased, which
resulted in unrealized gains on derivatives of approximately $734.7 million for
the year ended December 31, 2008. For information about the
Company’s credit risk related to derivative contracts see “Counterparty Credit
Risk” in “Liquidity and Capital Resources” below.
41
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Expenses
Lease
Operating Expenses
Lease
operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover
expenses. Lease operating expenses increased by approximately $17.2
million, or 15%, to $132.6 million for the year ended December 31, 2009,
from $115.4 million for the year ended December 31, 2008. Lease
operating expenses per Mcfe also increased, to $1.67 per Mcfe for the year ended
December 31, 2009, from $1.49 per Mcfe for the year ended December 31,
2008. Lease operating expenses increased primarily due to costs
associated with properties acquired in the first quarter of 2008 in the
Mid-Continent Shallow region and the third quarter of 2009 in the Permian Basin
region (see Note 2). Lease operating expenses are generally
higher for oil properties than for natural gas properties. Materials
and service cost increases across all operating regions and higher chemical and
treating costs associated with certain wells drilled in late 2008 also
contributed to the increase.
Transportation
Expenses
Transportation
expenses increased by approximately $0.6 million, or 3%, to $18.2 million for
the year ended December 31, 2009, from $17.6 million for the year ended
December 31, 2008, primarily due to increased production
volumes.
General and Administrative
Expenses
General
and administrative expenses are costs not directly associated with field
operations and include costs of employees and executive officers, related
benefits, office leases and professional fees. General and
administrative expenses increased by approximately $8.7 million, or 11%, to
$86.1 million for the year ended December 31, 2009, from $77.4 million for
the year ended December 31, 2008. General and administrative
expenses per Mcfe also increased, to $1.08 per Mcfe for the year ended
December 31, 2009, from $1.00 per Mcfe for the year ended December 31,
2008. The increase was primarily due to an increase in salaries and
benefits expense of approximately $7.3 million, driven primarily by an increase
in employee headcount.
Exploration
Costs
Exploration
costs decreased by approximately $0.4 million, or 5%, to $7.2 million for the
year ended December 31, 2009, from $7.6 million for the year ended
December 31, 2008. The decrease was primarily due to a decrease
in 3-D seismic and data library expense of approximately $2.2 million, partially
offset by an increase in impairment expense on unproved properties of
approximately $1.8 million.
Depreciation,
Depletion and Amortization
Depreciation,
depletion and amortization increased by approximately $7.7 million, or 4%, to
$201.8 million for the year ended December 31, 2009, from $194.1 million
for the year ended December 31, 2008. Higher total production
levels were the main reason for the increase. Depreciation, depletion
and amortization per Mcfe increased to $2.53 per Mcfe for the year ended
December 31, 2009, from $2.50 per Mcfe for the year ended December 31,
2008.
Impairment
of Goodwill and Long-Lived Assets
During
the year ended December 31, 2008, the Company recorded impairment expense
of approximately $50.5 million of which approximately $20.3 million was
associated with impairment of goodwill and approximately $30.2 million was
associated with impairment of proved oil and natural gas
properties. The Company recorded no impairment for the year ended
December 31, 2009. See Note 1 and “Critical Accounting Policies
and Estimates” below for additional information.
Taxes,
Other Than Income Taxes
Taxes,
other than income taxes, which consist primarily of production and ad valorem
taxes, decreased by approximately $33.8 million, or 55%, to $27.6 million for
the year ended December 31, 2009, from $61.4 million for the year ended
December 31, 2008. Production taxes, which are a function of
revenues generated from production, decreased by approximately $30.2 million
compared to the year ended December 31, 2008, primarily due to lower
commodity prices. Tax credits related to incentive programs for deep
wells and marketing deductions
42
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
also
contributed to the decrease. Ad valorem taxes, which are based on the
value of reserves and production equipment and vary by location, decreased
slightly compared to the year ended December 31, 2008.
(Gain)
Loss on Sale of Assets and Other, Net
The
Company recorded a gain of approximately $25.4 million from the sale of Woodford
Shale assets during the year ended December 31, 2009, (see
Note 2).
Other
Income and (Expenses)
|
Year
Ended
December 31,
|
||||||||||||
|
2009
|
2008
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Interest
expense, net of amounts capitalized
|
$ | (92,701 | ) | $ | (94,517 | ) | $ | 1,816 | ||||
|
Realized
loss on interest rate swaps
|
(42,941 | ) | (16,036 | ) | (26,905 | ) | ||||||
|
Unrealized
gain (loss) on interest rate swaps
|
16,588 | (50,638 | ) | 67,226 | ||||||||
|
Other,
net
|
(2,661 | ) | (7,702 | ) | 5,041 | |||||||
| $ | (121,715 | ) | $ | (168,893 | ) | $ | 47,178 | |||||
Other
income and (expenses) decreased by approximately $47.2 million during the year
ended December 31, 2009, compared to the year ended December 31,
2008. Interest expense decreased, driven by lower interest rates on
the Credit Facility due to lower LIBOR rates. The unrealized
mark-to-market change on interest rate swaps was a positive impact, as the
forward rate curve decreased less during the year ended December 31, 2009,
than it did during the year ended December 31, 2008. This was
partially offset by increased realized losses on interest rate swaps during the
year ended December 31, 2009, compared to the year ended December 31,
2008. In addition, the Company wrote off deferred financing fees of
approximately $6.7 million during the year ended December 31,
2008.
Income
Tax Benefit (Expense)
The
Company is a limited liability company treated as a partnership for federal and
state income tax purposes, with the exception of the state of Texas, with income
tax liabilities and/or benefits of the Company passed through to
unitholders. Limited liability companies are subject to state income
taxes in Texas. In addition, certain of the Company’s subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes. The Company recognized income tax benefit of approximately
$4.2 million and income tax expense of approximately $2.7 million for the years
ended December 31, 2009, and December 31, 2008,
respectively. Income tax benefit for the year ended December 31,
2009, is primarily due to a release of the valuation allowance on a significant
portion of deferred tax assets. Income tax expense for the year ended
December 31, 2008, primarily represents Texas margin tax expense.
Income
(Loss) From Continuing Operations
Income
(loss) from continuing operations was loss of approximately $295.8 million for
the year ended December 31, 2009, and income of approximately $825.7
million for the year ended December 31, 2008, due to lower oil, natural gas
and NGL revenues as a result of lower commodity prices during the year ended
December 31, 2009, combined with the impact of unrealized losses on commodity
derivatives.
Adjusted
EBITDA
Adjusted
EBITDA (a non-GAAP financial measure) increased by approximately $51.7 million,
or 10%, to $566.2 million for the year ended December 31, 2009, from $514.5
million for the year ended December 31, 2008,
43
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
primarily
due to increased realized gains on commodity derivatives, offset by lower oil,
natural gas and NGL revenues due to lower commodity prices. See
“Non-GAAP Financial Measures” on page 56 for a reconciliation of adjusted
EBITDA to its most directly comparable financial measure calculated and
presented in accordance with GAAP.
Year
Ended December 31, 2008, Compared to Year Ended December 31,
2007
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
and other:
|
||||||||||||
|
Natural
gas sales
|
$ | 334,214 | $ | 118,343 | $ | 215,871 | ||||||
|
Oil
sales
|
291,132 | 82,523 | 208,609 | |||||||||
|
NGL
sales
|
130,298 | 55,061 | 75,237 | |||||||||
|
Total
oil, natural gas and NGL sales
|
755,644 | 255,927 | 499,717 | |||||||||
|
Gain
(loss) on oil and natural gas derivatives (1)
|
662,782 | (345,537 | ) | 1,008,319 | ||||||||
|
Natural
gas marketing revenues
|
12,846 | 11,589 | 1,257 | |||||||||
|
Other
revenues
|
3,759 | 2,738 | 1,021 | |||||||||
| $ | 1,435,031 | $ | (75,283 | ) | $ | 1,510,314 | ||||||
|
Expenses:
|
||||||||||||
|
Lease
operating expenses
|
$ | 115,402 | $ | 41,946 | $ | 73,456 | ||||||
|
Transportation
expenses
|
17,597 | 5,575 | 12,022 | |||||||||
|
Natural
gas marketing expenses
|
11,070 | 9,100 | 1,970 | |||||||||
|
General
and administrative expenses (2)
|
77,391 | 51,374 | 26,017 | |||||||||
|
Exploration
costs
|
7,603 | 4,053 | 3,550 | |||||||||
|
Bad
debt expenses
|
1,436 | ― | 1,436 | |||||||||
|
Depreciation,
depletion and amortization
|
194,093 | 69,081 | 125,012 | |||||||||
|
Impairment
of goodwill and long-lived assets
|
50,505 | ― | 50,505 | |||||||||
|
Taxes,
other than income taxes
|
61,435 | 22,350 | 39,085 | |||||||||
|
(Gain)
loss on sale of assets and other, net
|
(98,763 | ) | 1,767 | (100,530 | ) | |||||||
| $ | 437,769 | $ | 205,246 | $ | 232,523 | |||||||
|
Other
income and (expenses)
|
$ | (168,893 | ) | $ | (70,877 | ) | $ | (98,016 | ) | |||
|
Income
(loss) from continuing operations before income taxes
|
$ | 828,369 | $ | (351,406 | ) | $ | 1,179,775 | |||||
|
Adjusted EBITDA (3)
|
$ | 514,487 | $ | 257,732 | $ | 256,755 | ||||||
|
Adjusted net income
(3)
|
$ | 174,663 | $ | 57,908 | $ | 116,755 | ||||||
|
(1)
|
During
the year ended December 31, 2008, the Company canceled (before the
contract settlement date) derivative contracts on estimated future natural
gas production primarily associated with properties in the Appalachian
Basin and Verden areas (see Note 2) resulting in realized losses of
approximately $81.4 million.
|
|
(2)
|
General
and administrative expenses for the years ended December 31, 2008,
and December 31, 2007, include approximately $14.6 million and $13.5
million, respectively, of noncash unit-based compensation
expenses.
|
|
(3)
|
This
is a non-GAAP measure used by management to analyze Company
performance. See “Non-GAAP Financial Measures” on page 56
for a reconciliation of the non-GAAP financial measure to its most
directly comparable financial measure calculated and presented in
accordance with GAAP.
|
44
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
Average
daily production:
|
||||||||||||
|
Natural
gas (MMcf/d)
|
124 | 51 | 143 | % | ||||||||
|
Oil
(MBbls/d)
|
8.6 | 3.4 | 153 | % | ||||||||
|
NGL
(MBbls/d)
|
6.2 | 2.7 | 130 | % | ||||||||
|
Total
(MMcfe/d)
|
212 | 87 | 144 | % | ||||||||
|
Weighted average prices
(hedged): (1)
|
||||||||||||
|
Natural
gas (Mcf)
|
$ | 8.42 | $ | 8.36 | 1 | % | ||||||
|
Oil
(Bbl)
|
$ | 80.92 | $ | 67.07 | 21 | % | ||||||
|
NGL
(Bbl)
|
$ | 57.86 | $ | 55.51 | 4 | % | ||||||
|
Weighted average prices
(unhedged): (2)
|
||||||||||||
|
Natural
gas (Mcf)
|
$ | 7.39 | $ | 6.39 | 16 | % | ||||||
|
Oil
(Bbl)
|
$ | 92.78 | $ | 66.44 | 40 | % | ||||||
|
NGL
(Bbl)
|
$ | 57.86 | $ | 55.51 | 4 | % | ||||||
|
Average
NYMEX prices:
|
||||||||||||
|
Natural
gas (MMBtu)
|
$ | 9.04 | $ | 6.86 | 32 | % | ||||||
|
Oil
(Bbl)
|
$ | 99.65 | $ | 72.34 | 38 | % | ||||||
|
Costs
per Mcfe of production:
|
||||||||||||
|
Lease
operating expenses
|
$ | 1.49 | $ | 1.31 | 14 | % | ||||||
|
Transportation
expenses
|
$ | 0.23 | $ | 0.17 | 35 | % | ||||||
|
General
and administrative expenses (3)
|
$ | 1.00 | $ | 1.61 | (38 | )% | ||||||
|
Depreciation,
depletion and amortization
|
$ | 2.50 | $ | 2.16 | 16 | % | ||||||
|
Taxes,
other than income taxes
|
$ | 0.79 | $ | 0.70 | 13 | % | ||||||
|
(1)
|
Includes
the effect of realized gains on derivatives of approximately $9.4 million
(excluding $81.4 million losses on canceled contracts) and $37.3 million
for the years ended December 31, 2008, and December 31, 2007,
respectively. The Company utilizes oil puts to hedge revenues
associated with its NGL production; therefore, all realized gains (losses)
on oil derivative contracts are included in weighted average oil prices,
rather than weighted average NGL
prices.
|
|
(2)
|
Does
not include the effect of realized gains (losses) on
derivatives.
|
|
(3)
|
General
and administrative expenses for the years ended December 31, 2008,
and December 31, 2007, include approximately $14.6 million and $13.5
million, respectively, of noncash unit-based compensation
expenses. Excluding these amounts, general and administrative
expenses for the years ended December 31, 2008, and December 31,
2007, were $0.81 per Mcfe and $1.19 per Mcfe,
respectively. This is a non-GAAP measure used by management to
analyze the Company’s performance.
|
45
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Revenues
and Other
Oil,
Natural Gas and NGL Sales
Oil,
natural gas and NGL sales increased by approximately $499.7 million, or
195%, to approximately $755.6 million for the year ended December 31, 2008,
from $255.9 million for the year ended December 31, 2007. Higher
oil, natural gas and NGL prices resulted in an increase in revenues of
approximately $82.6 million, $45.5 million and $5.3 million,
respectively.
Average
daily production increased to 212 MMcfe/d during the year ended
December 31, 2008, from 87 MMcfe/d during the year ended December 31,
2007. Volume increases during the year ended December 31, 2008,
resulted in an increase in total oil, natural gas and NGL revenues of
approximately $366.3 million compared to the year ended December 31,
2007.
The
following sets forth average daily production by region:
|
Year
Ended
December 31,
|
||||||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||||||
|
Average
daily production (MMcfe/d):
|
||||||||||||||||
|
Mid-Continent
Deep
|
136 | 47 | 89 | 189 | % | |||||||||||
|
Mid-Continent
Shallow
|
63 | 28 | 35 | 125 | % | |||||||||||
|
California
|
13 | 12 | 1 | 8 | % | |||||||||||
| 212 | 87 | 125 | 144 | % | ||||||||||||
The 189%
increase in average daily production in the Mid-Continent Deep region is
primarily due to the Company’s acquisition of properties in August 2007, which
contributed approximately 126 MMcfe per day during 2008. The 125%
increase in average daily production in the Mid-Continent Shallow region is
primarily due to the Company’s acquisition of properties in January 2008, which
contributed approximately 24 MMcfe per day during 2008. The
California region consists of a low-decline asset base and continues to produce
at levels consistent with the prior year.
Gain
(Loss) on Oil and Natural Gas Derivatives
The
Company determines the fair value of its oil and natural gas derivatives
utilizing pricing models that use a variety of techniques, including market
quotes and pricing analysis. See Note 7 and Note 8 for
additional information about commodity derivatives. During the year
ended December 31, 2008, the Company had commodity derivative contracts for
approximately 112% of its natural gas production and 82% of its oil and NGL
production, which resulted in realized losses of approximately $72.0 million
(including realized losses on canceled contracts of approximately $81.4
million). During the year ended December 31, 2008, the Company
canceled (before the contract settlement date) derivative contracts on estimated
future natural gas production primarily associated with properties in the
Appalachian Basin and Verden areas (see Note 2) resulting in realized
losses of $81.4 million. During the year ended December 31,
2007, the Company recorded realized gains of approximately $37.3
million. Unrealized gains and losses result from changes in market
valuations of derivatives as future commodity price expectations change compared
to the contract prices on the derivatives. During the second half of
2008, expected future oil and natural gas prices decreased, which resulted in
unrealized gains on derivatives of approximately $734.7 million for the year
ended December 31, 2008. During 2007, expected future oil and
natural gas prices increased, which resulted in unrealized losses on derivatives
of approximately $382.8 million for the year ended December 31,
2007. For information about the Company’s credit risk related to
derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital
Resources” below.
46
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Expenses
Lease
Operating Expenses
Lease
operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover
expenses. Lease operating expenses increased by approximately $73.5
million, or 175%, to $115.4 million for the year ended December 31, 2008,
from $41.9 million for the year ended December 31, 2007. Lease
operating expenses per Mcfe also increased, to $1.49 per Mcfe for the year ended
December 31, 2008, from $1.31 per Mcfe for the year ended December 31,
2007. Lease operating expenses increased primarily due to higher
production and costs associated with the 2007 and 2008 acquisitions in the
Mid-Continent Deep and Mid-Continent Shallow regions.
Transportation
Expenses
Transportation
expenses increased by approximately $12.0 million, or 214%, to $17.6 million for
the year ended December 31, 2008, from $5.6 million for the year ended
December 31, 2007, primarily due to increased production from the 2007 and
2008 acquisitions in the Mid-Continent Deep and Mid-Continent Shallow
regions.
General and Administrative
Expenses
General
and administrative expenses are costs not directly associated with field
operations and include costs of employees and executive officers, related
benefits, office leases and professional fees. General and
administrative expenses increased by approximately $26.0 million, or 51%, to
$77.4 million for the year ended December 31, 2008, from $51.4 million for
the year ended December 31, 2007. The increase in general and
administrative expenses was primarily due to costs incurred to support the
Company’s increased size and infrastructure growth, including the addition of a
regional operating office in Oklahoma. Salaries and benefits expense
and employee unit-based compensation expense increased approximately $17.2
million and $2.5 million, respectively, during the year ended December 31,
2008, compared to the year ended December 31, 2007. Information
technology costs, such as software, data administration and data conversion
costs increased by approximately $3.6 million during the year ended
December 31, 2008, compared to the year ended December 31,
2007. In addition, control of well insurance expense increased by
approximately $2.7 million during the year ended December 31, 2008,
primarily for properties in the Mid-Continent Deep region acquired in August
2007. The increase in general and administrative expenses was
partially offset by lower professional service fees, unit warrant expenses and
recovery of expenses under a transition services agreement.
Although
total general and administrative expenses increased, expenses per equivalent
unit of production decreased to $1.00 per Mcfe for the year ended
December 31, 2008, compared to $1.61 per Mcfe for the year ended
December 31, 2007, due to increases in production, cost efficiencies and
economies of scale provided by acquired properties.
Exploration
Costs
Exploration
costs increased by approximately $3.5 million, or 85%, to $7.6 million for the
year ended December 31, 2008, from $4.1 million for the year ended
December 31, 2007, primarily due to increased impairment expense on
unproved properties acquired in the Mid-Continent Deep region in August
2007.
Bad
Debt Expenses
During
the year ended December 31, 2008, the Company recorded bad debt expense of
approximately $1.4 million associated with accounts receivable from a customer
that filed for bankruptcy.
Depreciation,
Depletion and Amortization
Depreciation,
depletion and amortization increased by approximately $125.0 million, or 181%,
to $194.1 million for the year ended December 31, 2008, from $69.1 million
for the year ended December 31, 2007. Higher total production
levels, primarily due to the Company’s acquisitions in the Mid-Continent Deep
and Mid-Continent Shallow regions in 2007 and 2008, were the main reason for the
increase. Depreciation, depletion and amortization per Mcfe increased
to $2.50 per Mcfe for the year ended December 31, 2008, from $2.16 per Mcfe
for the year
47
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
ended
December 31, 2007, primarily due to higher depletion rates on properties
acquired in the Mid-Continent Deep region in August 2007, as compared to the
Company’s other properties.
Impairment
of Goodwill and Long-Lived Assets
During
the year ended December 31, 2008, the Company recorded impairment expense
of approximately $50.5 million of which approximately $20.3 million was
associated with impairment of goodwill and approximately $30.2 million was
associated with impairment of proved oil and natural gas
properties. See Note 1 and “Critical Accounting Policies and
Estimates” below for additional information.
Taxes,
Other Than Income Taxes
Taxes,
other than income taxes, which consist primarily of production and ad valorem
taxes, increased by approximately $39.0 million, or 174%, to $61.4 million for
the year ended December 31, 2008, from $22.4 million for the year ended
December 31, 2007. Production taxes, which are a function of
revenues generated from production, increased by approximately $32.4 million
compared to the year ended December 31, 2007. Ad valorem taxes,
which are based on the value of reserves and production equipment and vary by
location, increased by approximately $6.9 million compared to 2007.
(Gain)
Loss on Sale of Assets and Other, Net
The
Company recorded a gain of approximately $99.0 million from the sale of Woodford
Shale assets during the year ended December 31, 2008, (see
Note 2).
Other
Income and (Expenses)
|
Year
Ended
December 31,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Interest
expense, net of amounts capitalized
|
$ | (94,517 | ) | $ | (38,974 | ) | $ | (55,543 | ) | |||
|
Realized
gain (loss) on interest rate swaps
|
(16,036 | ) | 1,467 | (17,503 | ) | |||||||
|
Unrealized
loss on interest rate swaps
|
(50,638 | ) | (29,548 | ) | (21,090 | ) | ||||||
|
Other,
net
|
(7,702 | ) | (3,822 | ) | (3,880 | ) | ||||||
| $ | (168,893 | ) | $ | (70,877 | ) | $ | (98,016 | ) | ||||
Other
income and (expenses) increased by approximately $98.0 million, primarily due to
an increase in interest expense of approximately $55.5 million related to higher
debt levels associated with borrowings to fund acquisitions and
drilling. In addition, total losses on interest rate swaps increased
by approximately $38.6 million over the year ended December 31,
2007. The changes in fair values of these instruments were recorded
as unrealized losses of approximately $50.6 million and $29.5 million for the
years ended December 31, 2008, and December 31, 2007,
respectively.
Income
Tax Expense
The
Company is a limited liability company treated as a partnership for federal and
state income tax purposes, with the exception of the state of Texas, with income
tax liabilities and/or benefits of the Company passed through to
unitholders. Limited liability companies are subject to state income
taxes in Texas. In addition, certain of the Company’s subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes. Income tax expense was approximately $2.7 million and $4.8
million for the years ended December 31, 2008, and December 31, 2007,
respectively. Income tax expense for the year ended December 31,
2008, primarily represents Texas margin tax expense. Tax expense for
the year ended December 31, 2007, relates primarily to 2006 expense
recovery. The Company’s taxable subsidiaries generated net operating
losses for the year ended December 31, 2006. During the year
ended December 31, 2007, expenses were recovered by Linn Operating, Inc.
through an
48
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
intercompany
charge for services to LINN Energy, which resulted in income tax expense for
LINN Energy for the year ended December 31, 2007.
Income
(Loss) From Continuing Operations
Income
(loss) from continuing operations was income of approximately $825.7 million for
the year ended December 31, 2008, and loss of approximately $356.2 million
for the year ended December 31, 2007, due to increased production revenues
during the year ended December 31, 2008, resulting from the Company’s
acquisition of properties in August 2007 and January 2008, and to higher oil,
natural gas and NGL prices.
Adjusted
EBITDA
Adjusted
EBITDA (a non-GAAP financial measure) increased by approximately $256.8 million,
or 100%, to $514.5 million for the year ended December 31, 2008, from
$257.7 million for the year ended December 31, 2007, primarily due to
increased production revenues resulting from the Company’s acquisition of
properties in August 2007 and January 2008, and to higher oil, natural gas and
NGL prices. See “Non-GAAP Financial Measures” on page 56 for a
reconciliation of adjusted EBITDA to its most directly comparable financial
measure calculated and presented in accordance with GAAP.
Reserve
Replacement Metrics
The
Company calculates two primary reserve metrics: (i) reserve replacement cost and
(ii) reserve replacement ratio, to measure its ability to establish a long-term
trend of adding reserves at a reasonable cost. The reserve
replacement cost calculation provides an assessment of the cost of adding
reserves that is ultimately included in depreciation, depletion and amortization
expense. The reserve replacement ratio is an indicator of the
Company’s ability to replenish annual production volumes and grow
reserves. The metrics are calculated as follows:
|
Reserve
replacement cost per Mcfe
|
=
|
Oil
and natural gas capital costs expended (1)
|
|
Sum
of reserve additions (2)
|
||
|
Reserve
replacement ratio
|
=
|
Sum
of reserve additions (2)
|
|
Annual
production
|
|
(1)
|
Oil
and natural gas capital costs expended include the costs of property
acquisition, exploration and development activities conducted to add
reserves and exclude asset retirement obligation costs. The
Company expects to incur development costs in the future for proved
undeveloped reserves; such future costs are excluded from costs expended
and are not considered in the reserve replacement metrics presented
herein.
|
|
(2)
|
Reserve
additions include proved reserves (developed and undeveloped) and reflect
reserve revisions for prices and performance, extensions, discoveries and
other additions and acquisitions and do not include unproved reserve
quantities.
|
The
reserve replacement metrics are presented separately, both: (i) including and
excluding the impact of price revisions on reserves, to demonstrate the
effectiveness of the Company’s drilling program exclusive of economic factors
(such as price) outside of its control and (ii) including and excluding
acquisitions, to demonstrate the Company’s ability to add reserves through its
drilling program and through acquisitions. Reserve replacement cost
and reserve replacement ratio are non-GAAP financial measures. The
methods used by the Company to calculate these measures may differ from methods
used by other companies to compute similar measures. As a result, the
Company’s measures may not be comparable to similar measures provided by other
companies. The Company believes that providing such measures is
useful in evaluating the cost to add proved reserves; however, these measures
should not be considered in isolation or as a substitute for GAAP
measures. The reserve replacement cost per Mcfe and reserve
replacement ratio are statistical indicators that have limitations, including
their predictive and comparative value. The reserve replacement ratio
is limited because it may vary widely based on the extent and timing of new
discoveries, project sanctioning and property acquisitions. In
addition, since the reserve replacement
49
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
ratio
does not consider the development cost or timing of future production of new
reserves, it should not be used as a measure of value creation.
The
following presents reserve replacement cost and reserve replacement ratio from
continuing operations, including and excluding the effect of price revisions on
reserves:
|
Including
Price Revisions
|
Excluding
Price Revisions
|
|||||||||||||||||||||||
|
Year
Ended December 31,
|
Year
Ended December 31,
|
|||||||||||||||||||||||
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||||||||||||||
|
Costs
per Mcfe of production:
|
||||||||||||||||||||||||
|
Reserve
replacement cost, including acquisitions
|
$ | 1.96 | $ | 2.44 | $ | 2.23 | $ | 1.71 | $ | 1.53 | $ | 2.38 | ||||||||||||
|
Reserve
replacement cost, excluding acquisitions (finding and development
cost)
|
$ | 2.03 |
NM
(1)
|
$ | 1.16 | $ | 1.59 | $ | 1.44 | $ | 2.74 | |||||||||||||
|
Percentage
of production:
|
||||||||||||||||||||||||
|
Reserve
replacement ratio, including acquisitions
|
165 | % | 475 | % | 3,745 | % | 189 | % | 756 | % | 3,521 | % | ||||||||||||
|
Reserve
replacement ratio, excluding acquisitions
|
88 | % |
NM
(1)
|
389 | % | 112 | % | 282 | % | 165 | % | |||||||||||||
|
(1)
|
Not
meaningful due to the impact of a significant decrease in year-end
commodity prices, primarily oil, at December 31, 2008, compared to
December 31, 2007, which offset reserve
additions.
|
Amounts
used in these calculations reflect continuing operations only and are derived
directly from the table presented in “Supplemental Oil and Natural Gas Data
(Unaudited)” in Item 8. “Financial Statements and Supplementary
Data.” The following provides a reconciliation of oil and natural gas
capital costs used in these calculations to its most directly comparable
financial measure calculated and presented in accordance with GAAP:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Costs
incurred in oil and natural gas property acquisition, exploration
and development – continuing operations
|
$ | 258,105 | $ | 900,256 | $ | 2,674,439 | ||||||
|
Less:
|
||||||||||||
|
Asset
retirement obligation costs
|
(371 | ) | (680 | ) | (3,868 | ) | ||||||
|
Property
acquisition costs
|
(115,929 | ) | (584,630 | ) | (2,525,772 | ) | ||||||
|
Oil
and natural gas capital costs expended, excluding acquisitions –
continuing operations
|
$ | 141,805 | $ | 314,946 | $ | 144,799 | ||||||
Liquidity
and Capital Resources
The
Company utilizes funds from equity and debt offerings, bank borrowings and cash
generated from operations for capital resources and liquidity. To
date, the primary use of capital has been for the acquisition and development of
oil and natural gas properties. For the year ended December 31,
2009, the Company’s capital expenditures, excluding acquisitions, were
approximately $149.5 million. For 2010, the Company estimates its
capital expenditures, excluding acquisitions, will be between $150.0 million and
$175.0 million. This estimate is under continuous review and is
subject to ongoing adjustment. The Company expects to fund these
capital expenditures with cash flow from operations.
As the
Company pursues growth, it continually monitors the capital resources available
to meet future financial obligations and planned capital
expenditures. The Company’s future success in growing reserves and
production
50
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
will be
highly dependent on the capital resources available and its success in drilling
for or acquiring additional reserves. The Company actively reviews
acquisition opportunities on an ongoing basis. If the Company were to
make significant additional acquisitions for cash, it would need to borrow
additional amounts, if available, or obtain additional debt or equity
financing. The Company’s Credit Facility and other borrowings impose
certain restrictions on the Company’s ability to obtain additional debt
financing.
During
2009, the Company took several steps to strengthen its liquidity and extend its
weighted average debt maturities. In April 2009, the Company amended
and restated its existing Credit Facility to extend the maturity to August 2012,
and at January 29, 2010, the Company had $422.0 million in available
borrowing capacity under the Credit Facility. In addition, in May
2009, the Company issued $250.0 million in aggregate principal of 11.75% senior
notes due 2017 and used the net proceeds of approximately $230.8 million to
reduce indebtedness under its Credit Facility. In May 2009 and
October 2009, the Company completed public offerings of units for aggregate net
proceeds of approximately $279.3 million, which were used to reduce indebtedness
under the Credit Facility. Based upon current expectations the
Company believes liquidity and capital resources will be sufficient for the
conduct of its business and operations.
Statements
of Cash Flows
The
following is a comparative cash flow summary:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Net
cash:
|
||||||||||||
|
Provided
by (used in) operating activities (1)
|
$ | 426,804 | $ | 179,515 | $ | (44,814 | ) | |||||
|
Used
in investing activities
|
(282,273 | ) | (35,550 | ) | (2,892,420 | ) | ||||||
|
Provided
by (used in) financing activities
|
(150,968 | ) | (116,738 | ) | 2,932,080 | |||||||
|
Net
increase (decrease) in cash and cash equivalents
|
$ | (6,437 | ) | $ | 27,227 | $ | (5,154 | ) | ||||
|
(1)
|
The
years ended December 31, 2009, December 31, 2008, and
December 31, 2007, include premiums paid for derivatives of
approximately $93.6 million, $129.5 million and $279.3 million,
respectively.
|
Operating
Activities
Cash
provided by operating activities for the year ended December 31, 2009, was
approximately $426.8 million, compared to $179.5 million for the year ended
December 31, 2008. The increase was primarily due to higher
realized gains from oil and natural gas derivatives, offset by reduced revenues
associated with lower commodity prices in 2009.
In
comparison, cash used in operating activities was $44.8 million for the year
ended December 31, 2007. The use of cash for operating
activities was impacted by premiums paid for commodity derivatives of
approximately $279.3 million during the year ended December 31, 2007,
compared to $129.5 million during the year ended December 31,
2008. These commodity derivatives were utilized by the Company to
achieve a more predictable cash flow by reducing exposure to price fluctuations
and were funded through the Company’s Credit Facility.
Premiums
paid during 2009, 2008 and 2007, noted in the table above, were for commodity
derivative contracts that hedge future production. These derivative
contracts provide the Company long-term cash flow predictability to manage its
business, service debt and pay distributions and are primarily funded through
the Company’s Credit Facility. The amount of derivative contracts the
Company enters into in the future will be directly related to expected future
production. See Note 7 and Note 8 for additional details
about commodity derivatives.
51
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Investing
Activities
The
following provides a comparative summary of cash flow from investing
activities:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
flow from investing activities:
|
||||||||||||
|
Acquisition
of oil and natural gas properties
|
$ | (130,735 | ) | $ | (593,412 | ) | $ | (2,677,575 | ) | |||
|
Capital
expenditures
|
(178,242 | ) | (339,724 | ) | (219,383 | ) | ||||||
|
Proceeds
from sale of properties and equipment
|
26,704 | 897,586 | 4,538 | |||||||||
| $ | (282,273 | ) | $ | (35,550 | ) | $ | (2,892,420 | ) | ||||
The
primary use of cash in investing activities is for capital spending, which is
offset by proceeds from asset sales. Cash used in investing
activities was approximately $282.3 million for the year ended December 31,
2009, compared to $35.6 million for the year ended December 31,
2008. Cash used in investing activities for the year ended
December 31, 2009, includes approximately $114.4 million for the
acquisition of Permian Basin properties in the Mid-Continent Shallow region (see
Note 2).
Cash used
in investing activities for the year ended December 31, 2008, includes
approximately $510.6 million for the acquisition of properties in the
Mid-Continent Shallow region and proceeds from asset sales totaling
approximately $897.6 million, primarily from the sale of properties in the
Appalachian Basin, the Verden area in Oklahoma, and the Woodford Shale interval
in Oklahoma (see Note 2). In comparison, cash used in investing
activities was approximately $2.89 billion for the year ended December 31,
2007, and includes approximately $2.03 billion for the acquisition of properties
in the Mid-Continent Deep region and $555.5 million for the acquisition of
properties in the Mid-Continent Shallow region.
Financing
Activities
Cash used
in financing activities was approximately $151.0 million for the year ended
December 31, 2009, compared to $116.7 million for the year ended
December 31, 2008. The change in financing cash flow was
primarily due to increased operating cash flow and decreased acquisition and
development activity during 2009, which resulted in lower net borrowings
compared to 2008. In comparison, cash provided by financing
activities was $2.93 billion for the year ended December 31, 2007,
primarily due to $2.09 billion received from the sale of units in private
placement transactions (see Note 3). The following provides a
comparative summary of proceeds from borrowings and repayments of
debt:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Proceeds
from borrowings:
|
||||||||||||
|
Credit
facility
|
$ | 401,500 | $ | 809,000 | $ | 1,298,000 | ||||||
|
Senior
notes
|
237,703 | 250,000 | — | |||||||||
|
Term
loan
|
— | 400,000 | — | |||||||||
| $ | 639,203 | $ | 1,459,000 | $ | 1,298,000 | |||||||
|
Repayments
of debt:
|
||||||||||||
|
Credit
facility
|
$ | (704,893 | ) | $ | (848,608 | ) | $ | (280,750 | ) | |||
|
Term
loan
|
— | (400,000 | ) | — | ||||||||
|
Notes
payable
|
— | (1,564 | ) | (2,358 | ) | |||||||
| $ | (704,893 | ) | $ | (1,250,172 | ) | $ | (283,108 | ) | ||||
52
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Debt
On
April 28, 2009, the Company entered into an amended and restated Credit
Facility, with an initial borrowing base of $1.75 billion and a maturity of
August 2012, which amended and restated the Company’s existing credit facility,
which had a maturity of August 2010. The terms of the Credit Facility
required that, upon the issuance of the 2017 Notes in May 2009 (see below) and
cancellation of certain commodity derivatives in July 2009 (see Note 7),
the borrowing base be decreased by approximately $62.5 million and $45.0
million, respectively, to $1.64 billion, which remained the borrowing base at
January 29, 2010. At January 29, 2010, available borrowing
capacity was $422.0 million, which includes a $5.5 million reduction in
availability for outstanding letters of credit.
In May
2009, the Company issued $250.0 million in aggregate principal amount of the
Company’s 11.75% senior notes due 2017. The Company used the net
proceeds of approximately $230.8 million to reduce indebtedness under its Credit
Facility. In addition, in 2008, the Company issued $255.9 million in
aggregate principal amount of the Company’s 9.875% senior notes due
2018. The Company used the net proceeds of approximately $243.6
million to repay an outstanding term loan. For additional information
about the Company’s debt instruments, such as interest rates and covenants, see
Note 6. The Company is in compliance with all financial and
other covenants of the Credit Facility and senior notes.
The
Company depends on its Credit Facility for future capital needs. In
addition, the Company has drawn on the Credit Facility to fund or partially fund
quarterly cash distribution payments, since it uses operating cash flow for
investing activities and borrows as cash is needed. Absent such
borrowings, the Company would have at times experienced a shortfall in cash
available to pay the declared quarterly cash distribution amount. If
an event of default occurs and is continuing under the Credit Facility, the
Company would be unable to make borrowings to fund distributions. For
additional information about this and other risk factors that could affect the
Company, see Item 1A. “Risk Factors.”
Counterparty
Credit Risk
The
Company accounts for its commodity and interest rate derivatives at fair
value. The Company’s counterparties are participants or affiliates of
participants in its Credit Facility, which is secured by the Company’s oil,
natural gas and NGL reserves; therefore, the Company is not required to post any
collateral. The Company does not require collateral from its
counterparties. The Company minimizes the credit risk in derivative
instruments by: (i) limiting its exposure to any single counterparty;
(ii) entering into derivative instruments only with counterparties that
meet the Company’s minimum credit quality standard, or have a guarantee from an
affiliate that meets the Company’s minimum credit quality standard; and
(iii) monitoring the creditworthiness of the Company’s counterparties on an
ongoing basis. In accordance with the Company’s standard practice,
its commodity and interest rate derivatives are subject to counterparty netting
under agreements governing such derivatives and therefore the risk of loss due
to counterparty nonperformance is somewhat mitigated.
Public
Offering of Units
In
October 2009, the Company sold 8,625,000 units representing limited liability
company interests at $21.90 per unit ($21.024 per unit, net of underwriting
discount) for net proceeds of approximately $181.1 million. In
addition, in May 2009, the Company sold 6,325,000 units representing limited
liability company interests at $16.25 per unit ($15.60 per unit, net of
underwriting discount) for net proceeds of approximately $98.2
million. The Company used the net proceeds from each offering to
reduce indebtedness under the Credit Facility. See Note 3 for
additional information about the equity offerings.
53
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Distributions
Under the
limited liability company agreement, unitholders are entitled to receive a
quarterly distribution of available cash to the extent there is sufficient cash
from operations after establishment of cash reserves and payment of fees and
expenses. The following provides a summary of distributions paid by
the Company during the year ended December 31, 2009:
|
Date
Paid
|
Period
Covered by Distribution
|
Distribution
Per
Unit
|
Total
Distribution
|
|||||||
|
(in
millions)
|
||||||||||
|
November
2009
|
July
1 – September 30, 2009
|
$ | 0.63 | $ | 81.9 | |||||
|
August
2009
|
April
1 – June 30, 2009
|
$ | 0.63 | 76.4 | ||||||
|
May
2009
|
January
1 – March 31, 2009
|
$ | 0.63 | 72.5 | ||||||
|
February
2009
|
October
1 – December 31, 2008
|
$ | 0.63 | 72.5 | ||||||
| $ | 303.3 | |||||||||
On
January 27, 2010, the Company’s Board of Directors declared a cash
distribution of $0.63 per unit with respect to the fourth quarter of
2009. The distribution, totaling approximately $82.3 million, was
paid on February 12, 2010, to unitholders of record as of the close of
business on February 5, 2010.
Off-Balance
Sheet Arrangements
The
Company does not currently have any off-balance sheet arrangements.
Contingencies
In 2008,
Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity
Services Inc. (“Lehman Commodity Services”) filed voluntary petitions for
reorganization under Chapter 11 of the United States Bankruptcy
Code. At December 31, 2009, and December 31, 2008, the
Company had a net receivable of approximately $6.7 million from Lehman Commodity
Services for canceled derivative contracts, which is included in “other current
assets” on the consolidated balance sheets. The value of the
receivable was estimated based on market expectations. The Company is
pursuing various legal remedies to protect its interests and believes that the
ultimate disposition of this matter will not have a material adverse effect on
its business, financial position, results of operations or
liquidity.
During
the years ended December 31, 2009, December 31, 2008, and
December 31, 2007, the Company made no significant payments to settle any
legal, environmental or tax proceedings. The Company regularly
analyzes current information and accrues for probable liabilities on the
disposition of certain matters, as necessary. Liabilities for loss
contingencies arising from claims, assessments, litigation or other sources are
recorded when it is probable that a liability has been incurred and the amount
can be reasonably estimated.
54
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Commitments
and Contractual Obligations
The
following summarizes, as of December 31, 2009, certain long-term
contractual obligations that are reflected in the consolidated balance sheets
and/or disclosed in the accompanying notes thereto:
|
Payments
Due
|
||||||||||||||||||||
|
Contractual
Obligations
|
Total
|
2010
|
2011 – 2012 | 2013 – 2014 |
2015
and Beyond
|
|||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
Long-term
debt obligations:
|
||||||||||||||||||||
|
Credit
facility
|
$ | 1,100,000 | $ | — | $ | 1,100,000 | $ | — | $ | — | ||||||||||
|
Senior
notes
|
505,927 | — | — | — | 505,927 | |||||||||||||||
|
Interest
(1)
|
516,141 | 87,428 | 161,197 | 109,296 | 158,220 | |||||||||||||||
|
Operating
lease obligations:
|
||||||||||||||||||||
|
Office,
property and equipment leases
|
29,965 | 3,954 | 7,811 | 6,526 | 11,674 | |||||||||||||||
|
Other
noncurrent liabilities:
|
||||||||||||||||||||
|
Asset
retirement obligations
|
33,135 | — | — | — | 33,135 | |||||||||||||||
|
Other:
|
||||||||||||||||||||
|
Commodity
derivatives
|
45,654 | 8,185 | 5,787 | 14,271 | 17,411 | |||||||||||||||
|
Interest
rate swaps
|
69,386 | 42,839 | 26,547 | — | — | |||||||||||||||
|
Services
agreement
|
1,845 | 1,165 | 680 | — | — | |||||||||||||||
|
Charitable
contributions
|
750 | 250 | 500 | — | — | |||||||||||||||
|
Executive
severance
|
185 | 185 | — | — | — | |||||||||||||||
| $ | 2,302,988 | $ | 144,006 | $ | 1,302,522 | $ | 130,093 | $ | 726,367 | |||||||||||
|
(1)
|
Represents
interest on the Credit Facility computed at the weighted average LIBOR of
2.98% through maturity in August 2012 and interest on the 2017 Notes and
2018 Notes computed at fixed rates of 11.75% and 9.875% through maturity
in May 2017 and July 2018,
respectively.
|
Capital
Structure
The
Company’s capitalization is presented below:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Cash
and cash equivalents
|
$ | 22,231 | $ | 28,668 | ||||
|
Credit
facility
|
$ | 1,100,000 | $ | 1,403,393 | ||||
|
Senior
notes due 2017, net
|
238,275 | ― | ||||||
|
Senior
notes due 2018, net
|
250,556 | 250,175 | ||||||
| 1,588,831 | 1,653,568 | |||||||
|
Total
unitholders’ capital
|
2,452,004 | 2,760,686 | ||||||
| $ | 4,040,835 | $ | 4,414,254 | |||||
55
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Non-GAAP
Financial Measures
The
non-GAAP financial measures adjusted EBITDA and adjusted net income, as defined
by the Company, may not be comparable to similarly titled measures used by other
companies. Therefore, these non-GAAP measures should be considered in
conjunction with income from continuing operations and other performance
measures prepared in accordance with GAAP, such as operating income or cash flow
from operating activities. Adjusted EBITDA and adjusted net income
should not be considered in isolation or as a substitute for GAAP measures, such
as net income, operating income or any other GAAP measure of liquidity or
financial performance.
Adjusted
EBITDA (Non-GAAP Measure)
Adjusted
EBITDA is a measure used by Company management to indicate (prior to the
establishment of any reserves by its Board of Directors) the cash distributions
the Company expects to pay unitholders. Adjusted EBITDA is also a
quantitative measure used throughout the investment community with respect to
publicly-traded partnerships and limited liability companies.
The
Company defines adjusted EBITDA as income (loss) from continuing operations plus
the following adjustments:
|
|
·
|
Net
operating cash flow from acquisitions and divestitures, effective date
through closing date;
|
|
|
·
|
Interest
expense;
|
|
|
·
|
Depreciation,
depletion and amortization;
|
|
|
·
|
Impairment
of goodwill and long-lived assets;
|
|
|
·
|
Write-off
of deferred financing fees and
other;
|
|
|
·
|
(Gain)
loss on sale of assets, net;
|
|
|
·
|
Unrealized
(gain) loss on commodity
derivatives;
|
|
|
·
|
Unrealized
(gain) loss on interest rate
derivatives;
|
|
|
·
|
Realized
(gain) loss on interest rate
derivatives;
|
|
|
·
|
Realized
(gain) loss on canceled
derivatives;
|
|
|
·
|
Unit-based
compensation expenses;
|
|
|
·
|
Exploration
costs; and
|
|
|
·
|
Income
tax (benefit) expense.
|
56
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
The
following presents a reconciliation of consolidated income (loss) from
continuing operations to adjusted EBITDA:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Income
(loss) from continuing operations
|
$ | (295,841 | ) | $ | 825,657 | $ | (356,194 | ) | ||||
|
Plus:
|
||||||||||||
|
Net
operating cash flow from acquisitions and divestitures, effective date
through closing date (1)
|
3,708 | 3,436 | 67,417 | |||||||||
|
Interest
expense, cash
|
74,185 | 81,704 | 35,974 | |||||||||
|
Interest
expense, noncash
|
18,516 | 12,813 | 3,000 | |||||||||
|
Depreciation,
depletion and amortization
|
201,782 | 194,093 | 69,081 | |||||||||
|
Impairment
of goodwill and long-lived assets
|
— | 50,505 | — | |||||||||
|
Write-off
of deferred financing fees and other
|
204 | 6,728 | 3,460 | |||||||||
|
(Gain)
loss on sale of assets, net
|
(23,051 | ) | (98,763 | ) | 1,767 | |||||||
|
Unrealized
(gain) loss on commodity derivatives
|
591,379 | (734,732 | ) | 388,733 | ||||||||
|
Reclassification
of derivative settlements (2)
|
— | — | (5,946 | ) | ||||||||
|
Unrealized
(gain) loss on interest rate derivatives
|
(16,588 | ) | 50,638 | 29,548 | ||||||||
|
Realized
(gain) loss on interest rate derivatives (3)
|
42,881 | 16,036 | (1,467 | ) | ||||||||
|
Realized
(gain) loss on canceled derivatives
|
(48,977 | ) | 81,358 | — | ||||||||
|
Unit-based
compensation expenses
|
15,089 | 14,699 | 13,518 | |||||||||
|
Exploration
costs
|
7,169 | 7,603 | 4,053 | |||||||||
|
Income
tax (benefit) expense
|
(4,221 | ) | 2,712 | 4,788 | ||||||||
|
Adjusted
EBITDA from continuing operations
|
$ | 566,235 | $ | 514,487 | $ | 257,732 | ||||||
|
(1)
|
Includes
net operating cash flow from acquisitions and
divestitures.
|
|
(2)
|
During
2008, the Company revised its classification of realized and unrealized
gains (losses) on natural gas derivative contracts in order to match
realized gains (losses) with the related production. Amounts
reported in adjusted EBITDA for all prior periods have been reclassified
to conform to current period presentation. This
reclassification had no effect on the Company’s reported net
income.
|
|
(3)
|
During
2009, the Company revised its definition of adjusted EBITDA to include
realized (gains) losses on interest rate derivatives in order to match the
related interest expense. Amounts reported in adjusted EBITDA
for all prior periods have been reclassified to conform to current period
presentation. This reclassification had no effect on the
Company’s reported net income.
|
Net cash
provided by operating activities for the year ended December 31, 2009, was
approximately $426.8 million and includes cash interest payments of
approximately $73.9 million, premiums paid for commodity derivatives of
approximately $93.6 million, cash settlements on interest rate derivatives of
approximately $41.7 million, realized gains on canceled derivatives of
approximately $(49.0) million and other items of approximately $(20.8) million
that are not included in adjusted EBITDA. Net cash provided by
operating activities for the year ended December 31, 2008, was
approximately $179.5 million and includes cash interest payments of
approximately $95.0 million, premiums paid for commodity derivatives of
approximately $129.5 million, cash settlements on interest rate derivatives of
approximately $13.9 million, realized losses on canceled derivatives of
approximately $81.4 million and other items of approximately $15.2 million that
are not included in adjusted EBITDA. Net cash used in operating
activities for the year ended December 31, 2007, was approximately $(44.8)
million and includes cash interest payments of approximately $57.3 million,
premiums paid for commodity derivatives of approximately $279.3 million and
other items of approximately $(34.1) million that are not included in adjusted
EBITDA.
57
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Adjusted
Net Income (Non-GAAP Measure)
Adjusted
net income is a performance measure used by Company management to evaluate its
operational performance from oil and natural gas properties, prior to derivative
gains and losses, impairment of goodwill and long-lived assets and (gain) loss
on sale of assets, net.
The
following presents a reconciliation of income (loss) from continuing operations
to adjusted net income:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||
|
Income
(loss) from continuing operations
|
$ | (295,841 | ) | $ | 825,657 | $ | (356,194 | ) | ||||
|
Plus:
|
||||||||||||
|
Unrealized
(gain) loss on commodity derivatives
|
591,379 | (734,732 | ) | 388,733 | ||||||||
|
Reclassification
of derivative settlements
|
— | — | (5,946 | ) | ||||||||
|
Unrealized
(gain) loss on interest rate derivatives
|
(16,588 | ) | 50,638 | 29,548 | ||||||||
|
Realized
(gain) loss on canceled derivatives
|
(48,977 | ) | 81,358 | — | ||||||||
|
Impairment
of goodwill and long-lived assets
|
— | 50,505 | — | |||||||||
|
(Gain)
loss on sale of assets, net
|
(23,051 | ) | (98,763 | ) | 1,767 | |||||||
|
Adjusted
net income from continuing operations
|
$ | 206,922 | $ | 174,663 | $ | 57,908 | ||||||
|
Income
(loss) from continuing operations per unit – basic
|
$ | (2.48 | ) | $ | 7.18 | $ | (5.17 | ) | ||||
|
Plus,
per unit:
|
||||||||||||
|
Unrealized
(gain) loss on commodity derivatives
|
4.95 | (6.39 | ) | 5.64 | ||||||||
|
Reclassification
of derivative settlements
|
— | — | (0.09 | ) | ||||||||
|
Unrealized
(gain) loss on interest rate derivatives
|
(0.14 | ) | 0.44 | 0.43 | ||||||||
|
Realized
(gain) loss on canceled derivatives
|
(0.41 | ) | 0.71 | — | ||||||||
|
Impairment
of goodwill and long-lived assets
|
— | 0.44 | — | |||||||||
|
(Gain)
loss on sale of assets, net
|
(0.19 | ) | (0.86 | ) | 0.03 | |||||||
|
Adjusted
net income from continuing operations per unit – basic
|
$ | 1.73 | $ | 1.52 | $ | 0.84 | ||||||
58
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Critical
Accounting Policies and Estimates
The
discussion and analysis of the Company’s financial condition and results of
operations is based upon the consolidated financial statements, which have been
prepared in accordance with United States generally accepted accounting
principles (“GAAP”). The preparation of the consolidated financial
statements in conformity with GAAP requires management of the Company to make
estimates and assumptions about future events. These estimates and
the underlying assumptions affect the amount of assets and liabilities reported,
disclosures about contingent assets and liabilities, and reported amounts of
revenues and expenses. The estimates that are particularly
significant to the financial statements include estimates of the Company’s
reserves of oil, natural gas and NGL, future cash flows from oil and natural gas
properties, depreciation, depletion and amortization, asset retirement
obligations, fair values of commodity and interest rate derivatives, and fair
values of assets acquired and liabilities assumed. These estimates
and assumptions are based on management’s best estimates and
judgment. Management evaluates its estimates and assumptions on an
ongoing basis using historical experience and other factors, including the
current economic environment, which management believes to be reasonable under
the circumstances. Such estimates and assumptions are adjusted when
facts and circumstances dictate. Illiquid credit markets and volatile
equity and energy markets have combined to increase the uncertainty inherent in
such estimates and assumptions. As future events and their effects
cannot be determined with precision, actual results could differ from these
estimates. Any changes in estimates resulting from continuing changes
in the economic environment will be reflected in the financial statements in
future periods.
Below,
the Company has provided expanded discussion of its more significant accounting
policies, estimates and judgments, i.e., those that reflect more significant
estimates and assumptions used in the preparation of financial
statements. See Note 1 for details about additional accounting
policies and estimates made by Company management.
Oil
and Natural Gas Reserves
Proved
reserves are based on the quantities of oil, natural gas and NGL that by
analysis of geoscience and engineering data can be estimated with reasonable
certainty to be economically producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and
government regulations prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably
certain. The independent engineering firm DeGolyer and MacNaughton
prepared a reserve and economic evaluation of all of the Company properties on a
well-by-well basis as of December 31, 2009, and the reserve estimates
reported herein were prepared by DeGolyer and MacNaughton. The
reserve estimates were reviewed and approved by the Company’s senior engineering
staff and management, with final approval by its Senior Vice President and Chief
Operating Officer.
Reserves
and their relation to estimated future net cash flows impact the Company’s
depletion and impairment calculations. As a result, adjustments to
depletion and impairment are made concurrently with changes to reserve
estimates. The process performed by the independent engineers to
prepare reserve amounts included their estimation of reserve quantities, future
producing rates, future net revenue and the present value of such future net
revenue, based in part on data provided by the Company. The estimates
of reserves conform to the guidelines of the SEC, including the criteria of
“reasonable certainty,” as it pertains to expectations about the recoverability
of reserves in future years.
The
accuracy of reserve estimates is a function of many factors including the
following: the quality and quantity of available data, the interpretation of
that data, the accuracy of various mandated economic assumptions and the
judgments of the individuals preparing the estimates. In addition,
reserve estimates are a function of many assumptions, all of which could deviate
significantly from actual results. As such, reserve estimates may
materially vary from the ultimate quantities of oil, natural gas and NGL
eventually recovered. For additional information regarding estimates
of reserves, including the standardized measure of discounted future net cash
flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8.
“Financial Statements and Supplementary Data” and see also Item 1.
“Business.”
59
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Oil
and Natural Gas Properties
Proved
Properties
The
Company accounts for oil and natural gas properties in accordance with the
successful efforts method. In accordance with this method, all
leasehold and development costs of proved properties are capitalized and
amortized on a unit-of-production basis over the remaining life of the proved
reserves and proved developed reserves, respectively.
The
Company evaluates the impairment of its proved oil and natural gas properties on
a field-by-field basis whenever events or changes in circumstances indicate that
the carrying value may not be recoverable. The carrying values of
proved properties are reduced to fair value when the expected undiscounted
future cash flows are less than net book value. The fair values of
proved properties are measured using valuation techniques consistent with the
income approach, converting future cash flows to a single discounted
amount. Significant inputs used to determine the fair values of
proved properties include estimates of: (i) reserves; (ii) future
operating and development costs; (iii) future commodity prices; and
(iv) a market-based weighted average cost of capital rate. The
underlying commodity prices embedded in the Company’s estimated cash flows are
the product of a process that begins with NYMEX forward curve pricing, adjusted
for estimated location and quality differentials, as well as other factors that
Company management believes will impact realizable prices. Costs of
retired, sold or abandoned properties that constitute a part of an amortization
base are charged or credited, net of proceeds, to accumulated depreciation,
depletion and amortization unless doing so significantly affects the
unit-of-production amortization rate, in which case a gain or loss is recognized
currently. Gains or losses from the disposal of other properties are
recognized currently. Expenditures for maintenance and repairs
necessary to maintain properties in operating condition are expensed as
incurred. Estimated dismantlement and abandonment costs are
capitalized, net of salvage, at their estimated net present value and amortized
on a unit-of-production basis over the remaining life of the related proved
developed reserves. The Company capitalizes interest on borrowed
funds related to its share of costs associated with the drilling and completion
of new oil and natural gas wells. Interest is capitalized only during
the periods in which these assets are brought to their intended
use. The Company capitalized interest costs from continuing
operations of $0.3 million, $0.9 million and $0.5 million for the years
ended December 31, 2009, December 31, 2008, and December 31,
2007, respectively.
Unproved
Properties
Costs
related to unproved properties include costs incurred to acquire unproved
reserves. Because these reserves do not meet the definition of proved
reserves, the related costs are not classified as proved
properties. Unproved leasehold costs are capitalized and amortized on
a composite basis if individually insignificant, based on past success,
experience and average lease-term lives. Individually significant
leases are reclassified to proved properties if successful and expensed on a
lease by lease basis if unsuccessful or the lease term
expires. Unamortized leasehold costs related to successful
exploratory drilling are reclassified to proved properties and depleted on a
unit-of-production basis. The Company assesses unproved properties
for impairment quarterly on the basis of its experience in similar situations
and other factors such as the primary lease terms of the properties, the average
holding period of unproved properties, and the relative proportion of such
properties on which proved reserves have been found in the past. The
fair values of unproved properties are measured using valuation techniques
consistent with the income approach, converting future cash flows to a single
discounted amount. Significant inputs used to determine the fair
values of unproved properties include estimates of: (i) reserves;
(ii) future operating and development costs; (iii) future commodity
prices; and (iv) a market-based weighted average cost of capital
rate. The market-based weighted average cost of capital rate is
subjected to additional project-specific risking factors.
Impairment
Based on
the analysis described above, the Company recorded noncash impairment of proved
properties of approximately $30.2 million before and after tax for the year
ended December 31, 2008, which is included in “impairment of goodwill and
long-lived assets” on the consolidated statements of operations. The
Company recorded no impairment of proved properties in continuing operations for
the years ended December 31, 2009, or December 31,
2007. The Company recorded noncash impairment of unproved properties
of approximately $6.3 million and $4.5 million for the years ended
December 31, 2009, and December 31, 2008, which is included
in
60
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
“exploration
costs” on the consolidated statements of operations. The Company
recorded no such impairment for the year ended December 31,
2007.
Exploration
Costs
Geological
and geophysical costs, delay rentals, amortization and impairment of unproved
leasehold costs and costs to drill exploratory wells that do not find proved
reserves are expensed as exploration costs. The costs of any
exploratory wells are carried as an asset if the well finds a sufficient
quantity of reserves to justify its capitalization as a producing well and as
long as the Company is making sufficient progress towards assessing the reserves
and the economic and operating viability of the project.
Revenue
Recognition
Sales of
oil, natural gas and NGL are recognized when the product has been delivered to a
custody transfer point, persuasive evidence of a sales arrangement exists, the
rights and responsibility of ownership pass to the purchaser upon delivery,
collection of revenue from the sale is reasonably assured, and the sales price
is fixed or determinable.
The
Company has elected the entitlements method to account for natural gas
production imbalances. Imbalances occur when the Company sells more
or less than its entitled ownership percentage of total natural gas
production. In accordance with the entitlements method, any amount
received in excess of the Company’s share is treated as a
liability. If the Company receives less than its entitled share, the
underproduction is recorded as a receivable. At December 31,
2009, and December 31, 2008, the Company had natural gas production
imbalance receivables of approximately $16.4 million and $17.1 million,
respectively, which are included in “accounts receivable – trade, net” on
the consolidated balance sheets and natural gas production imbalance payables of
approximately $8.8 million and $9.9 million, respectively, which are included in
“accounts payable and accrued expenses” on the consolidated balance
sheets.
The
Company engages in the purchase, gathering and transportation of third-party
natural gas and subsequently markets such natural gas to independent purchasers
under separate arrangements. As such, the Company separately reports
third-party marketing sales and natural gas marketing
expenses. Marketing margins related to the Company’s production are
included in oil, natural gas and NGL sales.
Asset
Retirement Obligations
The
Company has the obligation to plug and abandon oil and natural gas wells and
related equipment at the end of production operations. Estimated
asset retirement costs are recognized when the obligation is incurred, and are
amortized over proved developed reserves using the units of production
method. Accretion expense is included in “depreciation, depletion and
amortization” on the consolidated statements of operations. The fair
values of additions to the asset retirement obligation liability are estimated
using valuation techniques that convert future cash flows to a single discounted
amount. Significant inputs to the valuation include estimates of:
(i) plug and abandon costs per well based on existing regulatory
requirements; (ii) remaining life per well; (iii) future inflation factors;
and (iv) a credit-adjusted risk-free interest rate. Revisions in
estimated liabilities can result from revisions of estimated inflation rates,
escalating retirement costs and changes in the estimated timing of settling
asset retirement obligations (see Note 10).
Derivative
Instruments
The
Company uses derivative financial instruments to reduce exposure to fluctuations
in the prices of oil, natural gas and NGL. By removing a significant
portion of the price volatility associated with future production, the Company
expects to mitigate, but not eliminate, the potential effects of variability in
cash flow from operations due to fluctuations in commodity
prices. These transactions are primarily in the form of swap
contracts, put options and collars. A swap contract specifies a fixed
price that the Company will receive from the counterparty as compared to
floating market prices, and on the settlement date the Company will receive or
pay the difference between the swap
61
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
price and
the market price. A put option requires the Company to pay the
counterparty a premium equal to the fair value of the option at the purchase
date and receive from the counterparty the excess, if any, of the fixed price
floor over the market price at the settlement date. A collar
specifies the range of prices that the Company will receive as compared to
floating market prices and on the settlement date offers the Company the
opportunity to receive up to the price ceiling while protecting against downside
risk below the price floor. In addition, the Company enters into
derivative contracts in the form of interest rate swaps to minimize the effects
of fluctuations in interest rates.
Derivative
instruments (including certain derivative instruments embedded in other
contracts) are recorded at fair value and included on the consolidated balance
sheets as assets or liabilities. The Company did not designate these
contracts as cash flow hedges; therefore, the changes in fair value of these
instruments are recorded in current earnings. The Company determines
the fair value of its derivative financial instruments utilizing pricing models
for significantly similar instruments. Inputs to the pricing models
include publicly available prices and forward price curves generated from a
compilation of data gathered from third parties. See Note 7 and
Note 8 for additional details about the Company’s derivative financial
instruments. See Item 7A. “Quantitative and Qualitative
Disclosures About Market Risk” for sensitivity analysis regarding the Company’s
derivative financial instruments.
Acquisition
Accounting
The
Company accounts for business combinations under the acquisition method of
accounting in accordance with an accounting standard adopted by the Company
effective January 1, 2009, (see Note 2). Accordingly, the
Company recognizes amounts for identifiable assets acquired and liabilities
assumed equal to their estimated acquisition date fair
values. Transaction and integration costs associated with business
combinations are expensed as incurred.
The
Company makes various assumptions in estimating the fair values of assets
acquired and liabilities assumed. As fair value is a market-based
measurement, it is determined based on the assumptions that market participants
would use. The most significant assumptions relate to the estimated
fair values of proved and unproved oil and natural gas
properties. The fair values of these properties are measured using
valuation techniques that convert future cash flows to a single discounted
amount. Significant inputs to the valuation include estimates of:
(i) reserves; (ii) future operating and development costs;
(iii) future commodity prices; and (iv) a market-based weighted
average cost of capital rate. The market-based weighted average cost
of capital rate is subjected to additional project-specific risking
factors. To compensate for the inherent risk of estimating and
valuing unproved properties, the discounted future net revenues of probable and
possible reserves are reduced by additional risk-weighting
factors. In addition, when appropriate, the Company reviews
comparable purchases and sales of oil and natural gas properties within the same
regions, and uses that data as a proxy for fair market value; i.e., the amount a
willing buyer and seller would enter into in exchange for such
properties.
Any
excess of the acquisition price over the estimated fair value of net assets
acquired is recorded as goodwill while any excess of the estimated fair value of
net assets acquired over the acquisition price is recorded in current earnings
as a gain. Deferred taxes are recorded for any differences between
the assigned values and the tax basis of assets and
liabilities. Estimated deferred taxes are based on available
information concerning the tax basis of assets acquired and liabilities assumed
and loss carryforwards at the acquisition date, although such estimates may
change in the future as additional information becomes known.
While the
estimated fair values of the assets acquired and liabilities assumed have no
effect on cash flow, they can have an effect on future results of
operations. Generally, higher fair values assigned to oil and natural
gas properties result in higher future depreciation, depletion and amortization
expense, which results in decreased future net earnings. Also, a
higher fair value assigned to oil and natural gas properties, based on higher
future estimates of commodity prices, could increase the likelihood of
impairment in the event of lower commodity prices or higher operating costs than
those originally used to determine fair value. The recording of
impairment expense has no effect on cash flow but results in a decrease in net
income for the period in which the impairment is recorded.
62
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Unit-Based
Compensation
The
Company recognizes expense for unit-based compensation over the requisite
service period, in an amount equal to the fair value of unit-based payments
granted to employees and nonemployee directors. See Note 1 and
Note 5 for additional details about the Company’s accounting for unit-based
compensation.
New
Accounting Standards
See
Note 12 and Note 17 for details regarding the Company’s implementation
of new accounting standards.
The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from
adverse changes in commodity prices and interest rates. The
disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonably possible losses. This
forward-looking information provides indicators of how the Company views and
manages its ongoing market risk exposures. All of the Company’s
market risk sensitive instruments were entered into for purposes other than
trading.
The
following should be read in conjunction with the financial statements and
related notes included elsewhere in this Annual Report on
Form 10-K. A reference to a “Note” herein refers to the
accompanying Notes to Consolidated Financial Statements contained in
Item 8. “Financial Statements and Supplementary Data.”
Commodity
Price Risk
The
Company enters into derivative contracts with respect to a portion of its
projected production through various transactions that provide an economic hedge
of the risk related to the future prices received. The Company does
not enter into derivative contracts for trading purposes (see
Note 7). At December 31, 2009, the fair value of contracts
that settle during the next 12 months was an asset of approximately $227.6
million and a liability of $8.1 for a net asset of approximately $219.5
million. A 10% increase in the index oil and natural gas prices above
the December 31, 2009, prices for the next 12 months would result in a net
asset of approximately $130.7 million which represents a decrease in the fair
value of approximately $88.8 million; conversely, a 10% decrease in the index
oil and natural gas prices would result in a net asset of approximately $310.3
million which represents an increase in the fair value of approximately $90.8
million.
Interest
Rate Risk
At
December 31, 2009, the Company had long-term debt outstanding under its
Credit Facility of approximately $1.10 billion, which incurred interest at
floating rates (see Note 6). A 1% increase in LIBOR would result
in an estimated $11.0 million increase in annual interest
expense. The Company has entered into interest rate swap agreements
based on LIBOR to minimize the effect of fluctuations in interest rates (see
Note 7).
Counterparty
Credit Risk
The
Company accounts for its commodity and interest rate derivatives at fair value
on a recurring basis (see Note 8). The fair value of these
derivative financial instruments includes the impact of assumed credit risk
adjustments, which are based on the Company’s and counterparties’ published
credit ratings, public bond yield spreads and credit default swap spreads, as
applicable.
At
December 31, 2009, the average public bond yield spread utilized to
estimate the impact of the Company’s credit risk on derivative liabilities was
approximately 4.25%. A 1% increase in the average public bond yield
spread would result in an estimated $2.1 million increase in net income for the
year ended December 31, 2009. At December 31, 2009, the
credit default swap spreads utilized to estimate the impact of counterparties’
credit risk on derivative assets ranged between 0% and 1.35%. A 1%
increase in each of the counterparties’ credit default swap spreads would result
in an estimated $3.3 million decrease in net income for the year ended
December 31, 2009.
|
Page
|
|
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of
the Securities Exchange Act of 1934, as amended. Our internal control
over financial reporting is a process designed under the supervision of our
Chief Executive Officer and Chief Financial Officer to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of consolidated financial statements for external purposes in accordance with
accounting principles generally accepted in the United States.
Because
of its inherent limitations, internal control over financial reporting may not
detect or prevent misstatements. Projections of any evaluation of the
effectiveness to future periods are subject to risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or processes may deteriorate.
As of
December 31, 2009, our management assessed the effectiveness of the
Company’s internal control over financial reporting based on the criteria for
effective internal control over financial reporting established in Internal Control – Integrated Framework, issued
by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on the assessment, management determined that we
maintained effective internal control over financial reporting as of
December 31, 2009, based on those criteria. KPMG LLP, the
independent registered public accounting firm that audited the consolidated
financial statements of the Company included in this Annual Report on Form 10-K,
has issued an attestation report on the effectiveness of the Company’s internal
control over financial reporting as of December 31, 2009, which is included
herein.
/s/ Linn
Energy, LLC
The Board
of Directors and Unitholders
Linn
Energy, LLC:
We have
audited the accompanying consolidated balance sheets of Linn Energy, LLC and
subsidiaries as of December 31, 2009 and 2008, and the related consolidated
statements of operations, unitholders’ capital, and cash flows for each of the
years in the three-year period ended December 31, 2009. These
consolidated financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these
consolidated 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. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements. An audit also includes 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, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Linn Energy, LLC and
subsidiaries as of December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2009, in conformity with U.S. generally accepted
accounting principles.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Linn Energy, LLC’s internal control over
financial reporting as of December 31, 2009, based on criteria established
in Internal
Control–Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 25, 2010,
expressed an unqualified opinion on the effectiveness of the Company’s internal
control over financial reporting.
/s/ KPMG
LLP
Houston,
Texas
February 25,
2010
The Board
of Directors and Unitholders
Linn
Energy, LLC:
We have
audited Linn Energy, LLC’s internal control over financial reporting as of
December 31, 2009, based on criteria established in Internal Control–Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Linn Energy, LLC’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report on Internal Control
Over Financial Reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting based on our
audit.
We
conducted our audit 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
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audit also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our
opinion, Linn Energy, LLC maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on
criteria established in Internal Control–Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We also
have audited, in accordance with the standards the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Linn Energy,
LLC and subsidiaries as of December 31, 2009 and 2008, and the related
consolidated statements of operations, unitholders’ capital and cash flows for
each of the years in the three-year period ended December 31, 2009, and our
report dated February 25, 2010, expressed an unqualified opinion on those
consolidated financial statements.
/s/ KPMG
LLP
Houston,
Texas
February 25,
2010
CONSOLIDATED
BALANCE SHEETS
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands,
except
unit amounts)
|
||||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 22,231 | $ | 28,668 | ||||
|
Accounts
receivable – trade, net
|
109,311 | 138,983 | ||||||
|
Derivative
instruments
|
249,756 | 368,951 | ||||||
|
Other
current assets
|
28,162 | 27,329 | ||||||
|
Total
current assets
|
409,460 | 563,931 | ||||||
|
Noncurrent
assets:
|
||||||||
|
Oil
and natural gas properties (successful efforts method)
|
4,076,795 | 3,831,183 | ||||||
|
Less
accumulated depletion and amortization
|
(463,413 | ) | (278,805 | ) | ||||
| 3,613,382 | 3,552,378 | |||||||
|
Other
property and equipment
|
118,867 | 111,459 | ||||||
|
Less
accumulated depreciation
|
(23,583 | ) | (13,171 | ) | ||||
| 95,284 | 98,288 | |||||||
|
Derivative
instruments
|
145,457 | 493,705 | ||||||
|
Other
noncurrent assets
|
76,673 | 13,718 | ||||||
| 222,130 | 507,423 | |||||||
|
Total
noncurrent assets
|
3,930,796 | 4,158,089 | ||||||
|
Total
assets
|
$ | 4,340,256 | $ | 4,722,020 | ||||
|
LIABILITIES
AND UNITHOLDERS’ CAPITAL
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable and accrued expenses
|
$ | 124,358 | $ | 163,662 | ||||
|
Derivative
instruments
|
51,025 | 47,005 | ||||||
|
Other
accrued liabilities
|
33,922 | 27,163 | ||||||
|
Total
current liabilities
|
209,305 | 237,830 | ||||||
|
Noncurrent
liabilities:
|
||||||||
|
Credit
facility
|
1,100,000 | 1,403,393 | ||||||
|
Senior
notes, net
|
488,831 | 250,175 | ||||||
|
Derivative
instruments
|
53,923 | 39,350 | ||||||
|
Other
noncurrent liabilities
|
36,193 | 30,586 | ||||||
|
Total
noncurrent liabilities
|
1,678,947 | 1,723,504 | ||||||
|
Unitholders’
capital:
|
||||||||
|
129,940,617
units and 114,079,533 units issued and outstanding at December 31,
2009, and December 31, 2008, respectively
|
2,098,599 | 2,109,089 | ||||||
|
Accumulated
income
|
353,405 | 651,597 | ||||||
| 2,452,004 | 2,760,686 | |||||||
|
Total
liabilities and unitholders’ capital
|
$ | 4,340,256 | $ | 4,722,020 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||
|
Revenues
and other:
|
||||||||||||
|
Oil,
natural gas and natural gas liquid sales
|
$ | 408,219 | $ | 755,644 | $ | 255,927 | ||||||
|
Gain
(loss) on oil and natural gas derivatives
|
(141,374 | ) | 662,782 | (345,537 | ) | |||||||
|
Natural
gas marketing revenues
|
4,380 | 12,846 | 11,589 | |||||||||
|
Other
revenues
|
1,924 | 3,759 | 2,738 | |||||||||
| 273,149 | 1,435,031 | (75,283 | ) | |||||||||
|
Expenses:
|
||||||||||||
|
Lease
operating expenses
|
132,647 | 115,402 | 41,946 | |||||||||
|
Transportation
expenses
|
18,202 | 17,597 | 5,575 | |||||||||
|
Natural
gas marketing expenses
|
2,154 | 11,070 | 9,100 | |||||||||
|
General
and administrative expenses
|
86,134 | 77,391 | 51,374 | |||||||||
|
Exploration
costs
|
7,169 | 7,603 | 4,053 | |||||||||
|
Bad
debt expenses
|
401 | 1,436 | ― | |||||||||
|
Depreciation,
depletion and amortization
|
201,782 | 194,093 | 69,081 | |||||||||
|
Impairment
of goodwill and long-lived assets
|
― | 50,505 | ― | |||||||||
|
Taxes,
other than income taxes
|
27,605 | 61,435 | 22,350 | |||||||||
|
(Gain)
loss on sale of assets and other, net
|
(24,598 | ) | (98,763 | ) | 1,767 | |||||||
| 451,496 | 437,769 | 205,246 | ||||||||||
|
Other
income and (expenses):
|
||||||||||||
|
Interest
expense, net of amounts capitalized
|
(92,701 | ) | (94,517 | ) | (38,974 | ) | ||||||
|
Loss
on interest rate swaps
|
(26,353 | ) | (66,674 | ) | (28,081 | ) | ||||||
|
Other,
net
|
(2,661 | ) | (7,702 | ) | (3,822 | ) | ||||||
| (121,715 | ) | (168,893 | ) | (70,877 | ) | |||||||
|
Income
(loss) from continuing operations before income taxes
|
(300,062 | ) | 828,369 | (351,406 | ) | |||||||
|
Income
tax benefit (expense)
|
4,221 | (2,712 | ) | (4,788 | ) | |||||||
|
Income
(loss) from continuing operations
|
(295,841 | ) | 825,657 | (356,194 | ) | |||||||
|
Discontinued
operations:
|
||||||||||||
|
Gain
(loss) on sale of assets, net of taxes
|
(158 | ) | 159,045 | 936 | ||||||||
|
Income
(loss) from discontinued operations, net of taxes
|
(2,193 | ) | 14,914 | (9,091 | ) | |||||||
| (2,351 | ) | 173,959 | (8,155 | ) | ||||||||
|
Net
income (loss)
|
$ | (298,192 | ) | $ | 999,616 | $ | (364,349 | ) | ||||
|
Income
(loss) per unit – continuing operations:
|
||||||||||||
|
Basic
|
$ | (2.48 | ) | $ | 7.18 | $ | (5.17 | ) | ||||
|
Diluted
|
$ | (2.48 | ) | $ | 7.18 | $ | (5.17 | ) | ||||
|
Income
(loss) per unit – discontinued operations:
|
||||||||||||
|
Basic
|
$ | (0.02 | ) | $ | 1.52 | $ | (0.12 | ) | ||||
|
Diluted
|
$ | (0.02 | ) | $ | 1.52 | $ | (0.12 | ) | ||||
|
Net
income (loss) per unit:
|
||||||||||||
|
Basic
|
$ | (2.50 | ) | $ | 8.70 | $ | (5.29 | ) | ||||
|
Diluted
|
$ | (2.50 | ) | $ | 8.70 | $ | (5.29 | ) | ||||
|
Weighted
average units outstanding:
|
||||||||||||
|
Basic
|
119,307 | 114,140 | 68,916 | |||||||||
|
Diluted
|
119,307 | 114,158 | 68,916 | |||||||||
|
Distributions
declared per unit
|
$ | 2.52 | $ | 2.52 | $ | 2.18 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED
STATEMENTS OF UNITHOLDERS’ CAPITAL
|
Units
|
Unitholders’
Capital
|
Accumulated
Income
(Deficit)
|
Treasury
Units
(at
Cost)
|
Total
Unitholders’
Capital
|
||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
December
31, 2006
|
42,803 | $ | 434,624 | $ | 16,330 | $ | ― | $ | 450,954 | |||||||||||
|
Sale
of units, net of expenses of $34,334
|
69,874 | 2,085,666 | ― | ― | 2,085,666 | |||||||||||||||
|
Issuance
of units
|
1,366 | 2,811 | ― | ― | 2,811 | |||||||||||||||
|
Cancellation
of units
|
(227 | ) | (7,399 | ) | ― | 7,399 | ― | |||||||||||||
|
Purchase
of units
|
― | ― | (7,399 | ) | (7,399 | ) | ||||||||||||||
|
Distributions
to unitholders
|
(154,963 | ) | ― | ― | (154,963 | ) | ||||||||||||||
|
Unit-based
compensation expenses
|
13,921 | ― | ― | 13,921 | ||||||||||||||||
|
Net
loss
|
― | (364,349 | ) | ― | (364,349 | ) | ||||||||||||||
|
December
31, 2007
|
113,816 | 2,374,660 | (348,019 | ) | ― | 2,026,641 | ||||||||||||||
|
Issuance
of units
|
1,435 | 23,483 | ― | ― | 23,483 | |||||||||||||||
|
Cancellation
of units
|
(1,171 | ) | (14,998 | ) | ― | 14,998 | ― | |||||||||||||
|
Purchase
of units
|
― | ― | (14,998 | ) | (14,998 | ) | ||||||||||||||
|
Distributions
to unitholders
|
(289,915 | ) | ― | ― | (289,915 | ) | ||||||||||||||
|
Unit-based
compensation expenses
|
15,677 | ― | ― | 15,677 | ||||||||||||||||
|
Reclassification
of distributions paid on forfeited restricted units
|
182 | ― | ― | 182 | ||||||||||||||||
|
Net
income
|
― | 999,616 | ― | 999,616 | ||||||||||||||||
|
December 31,
2008
|
114,080 | 2,109,089 | 651,597 | ― | 2,760,686 | |||||||||||||||
|
Sale
of units, net of underwriting discounts and expenses of
$12,369
|
14,950 | 279,299 | ― | ― | 279,299 | |||||||||||||||
|
Issuance
of units
|
1,098 | 494 | ― | ― | 494 | |||||||||||||||
|
Cancellation
of units
|
(187 | ) | (2,696 | ) | ― | 2,696 | ― | |||||||||||||
|
Purchase
of units
|
― | ― | (2,696 | ) | (2,696 | ) | ||||||||||||||
|
Distributions
to unitholders
|
(303,316 | ) | ― | ― | (303,316 | ) | ||||||||||||||
|
Unit-based
compensation expenses
|
15,089 | ― | ― | 15,089 | ||||||||||||||||
|
Reclassification
of distributions paid on forfeited restricted units
|
63 | ― | ― | 63 | ||||||||||||||||
|
Excess
tax benefit from unit-based compensation
|
577 | ― | ― | 577 | ||||||||||||||||
|
Net
loss
|
― | (298,192 | ) | ― | (298,192 | ) | ||||||||||||||
|
December 31,
2009
|
129,941 | $ | 2,098,599 | $ | 353,405 | $ | ― | $ | 2,452,004 | |||||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
flow from operating activities:
|
||||||||||||
|
Net
income (loss)
|
$ | (298,192 | ) | $ | 999,616 | $ | (364,349 | ) | ||||
|
Adjustments
to reconcile net income (loss) to net cash provided by
(used in) operating activities:
|
||||||||||||
|
Depreciation,
depletion and amortization
|
201,782 | 200,306 | 94,200 | |||||||||
|
Impairment
of goodwill and long-lived assets
|
― | 50,505 | 3,343 | |||||||||
|
Unit-based
compensation expenses
|
15,089 | 15,677 | 13,921 | |||||||||
|
Bad
debt expenses
|
401 | 1,436 | ― | |||||||||
|
Amortization
and write-off of deferred financing fees and other
|
21,824 | 17,024 | 5,746 | |||||||||
|
(Gain)
loss on sale of assets, net
|
(23,243 | ) | (257,808 | ) | 831 | |||||||
|
Deferred
income tax
|
(6,436 | ) | ― | 3,360 | ||||||||
|
Mark-to-market
on derivatives:
|
||||||||||||
|
Total
(gains) losses
|
167,727 | (596,108 | ) | 373,618 | ||||||||
|
Cash
settlements
|
362,936 | (20,901 | ) | 40,784 | ||||||||
|
Cash
settlements on canceled derivatives
|
48,977 | (81,358 | ) | ― | ||||||||
|
Premiums
paid for derivatives
|
(93,606 | ) | (129,520 | ) | (279,313 | ) | ||||||
|
Changes
in assets and liabilities:
|
||||||||||||
|
(Increase)
decrease in accounts receivable – trade, net
|
29,117 | 9,572 | (117,361 | ) | ||||||||
|
(Increase)
decrease in other assets
|
(3,051 | ) | (8,455 | ) | 3,286 | |||||||
|
Increase
(decrease) in accounts payable and accrued expenses
|
(4,675 | ) | (36,451 | ) | 161,844 | |||||||
|
Increase
in other liabilities
|
8,154 | 15,980 | 15,276 | |||||||||
|
Net
cash provided by (used in) operating activities
|
426,804 | 179,515 | (44,814 | ) | ||||||||
|
Cash
flow from investing activities:
|
||||||||||||
|
Acquisition
of oil and natural gas properties
|
(130,735 | ) | (593,412 | ) | (2,677,575 | ) | ||||||
|
Development
of oil and natural gas properties
|
(170,458 | ) | (330,615 | ) | (185,534 | ) | ||||||
|
Purchases
of other property and equipment
|
(7,784 | ) | (9,109 | ) | (33,849 | ) | ||||||
|
Proceeds
from sale of properties and equipment
|
26,704 | 897,586 | 4,538 | |||||||||
|
Net
cash used in investing activities
|
(282,273 | ) | (35,550 | ) | (2,892,420 | ) | ||||||
|
Cash
flow from financing activities:
|
||||||||||||
|
Proceeds
from sale of units
|
291,668 | ― | 2,120,000 | |||||||||
|
Purchase
of units
|
(2,696 | ) | (14,998 | ) | (7,399 | ) | ||||||
|
Proceeds
from borrowings
|
639,203 | 1,459,000 | 1,298,000 | |||||||||
|
Repayments
of debt
|
(704,893 | ) | (1,250,172 | ) | (283,108 | ) | ||||||
|
Distributions
to unitholders
|
(303,316 | ) | (289,915 | ) | (154,963 | ) | ||||||
|
Financing
fees, offering expenses and other, net
|
(70,934 | ) | (20,653 | ) | (40,450 | ) | ||||||
|
Net
cash provided by (used in) financing activities
|
(150,968 | ) | (116,738 | ) | 2,932,080 | |||||||
|
Net
increase (decrease) in cash and cash equivalents
|
(6,437 | ) | 27,227 | (5,154 | ) | |||||||
|
Cash
and cash equivalents:
|
||||||||||||
|
Beginning
|
28,668 | 1,441 | 6,595 | |||||||||
|
Ending
|
$ | 22,231 | $ | 28,668 | $ | 1,441 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
|
(1)
|
Basis
of Presentation and Significant Accounting
Policies
|
(a) Nature
of Business
Linn
Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural
gas company that began operations in March 2003 and was formed as a Delaware
limited liability company in April 2005. The Company completed its
initial public offering (“IPO”) in January 2006 and its units representing
limited liability company interests (“units”) are listed on The NASDAQ Global
Select Market under the symbol “LINE.” LINN Energy’s mission is to
acquire, develop and maximize cash flow from a growing portfolio of long-life
oil and natural gas assets. The Company’s properties are located in
the United States, primarily in the Mid-Continent, California and the Permian
Basin.
The
operations of the Company are governed by the provisions of a limited liability
company agreement executed by and among its members. The agreement
includes specific provisions with respect to the maintenance of the capital
accounts of each of the Company’s unitholders. Pursuant to applicable
provisions of the Delaware Limited Liability Company Act (the “Delaware Act”)
and the Second Amended and Restated Limited Liability Company Agreement of Linn
Energy, LLC, as amended (the “Agreement”), unitholders have no liability for the
debts, obligations and liabilities of the Company, except as expressly required
in the Agreement or the Delaware Act. The Company will remain in
existence unless and until dissolved in accordance with the terms of the
Agreement.
(b) Principles
of Consolidation and Reporting
The
Company presents its financial statements in accordance with United States
generally accepted accounting principles (“GAAP”). The consolidated
financial statements include the accounts of the Company and its wholly owned
subsidiaries. All significant intercompany transactions and balances
have been eliminated upon consolidation. Subsequent events were
evaluated through the issuance date of the financial statements.
(c) Discontinued
Operations
The
Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. (“Mid Atlantic”)
operations have been classified as discontinued operations on the consolidated
statements of operations for all periods presented. Unless otherwise
indicated, information about the consolidated statements of operations that is
presented in the notes to consolidated financial statements relates only to
continuing operations.
(d) Use
of Estimates
The
preparation of the accompanying consolidated financial statements in conformity
with GAAP requires management of the Company to make estimates and assumptions
about future events. These estimates and the underlying assumptions
affect the amount of assets and liabilities reported, disclosures about
contingent assets and liabilities, and reported amounts of revenues and
expenses. The estimates that are particularly significant to the
financial statements include estimates of the Company’s reserves of oil, natural
gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas
properties, depreciation, depletion and amortization, asset retirement
obligations, fair values of commodity and interest rate derivatives, and fair
values of assets acquired and liabilities assumed. As fair value is a
market-based measurement, it is determined based on the assumptions that market
participants would use. These estimates and assumptions are based on
management’s best estimates and judgment. Management evaluates its
estimates and assumptions on an ongoing basis using historical experience and
other factors, including the current economic environment, which management
believes to be reasonable under the circumstances. Such estimates and
assumptions are adjusted when facts and circumstances
dictate. Illiquid credit markets and volatile equity and energy
markets have combined to increase the uncertainty inherent in such estimates and
assumptions. As future events and their effects
cannot be
determined with precision, actual results could differ from these
estimates. Any changes in estimates resulting from continuing changes
in the economic environment will be reflected in the financial statements in
future periods.
(e) Cash
Equivalents
For
purposes of the consolidated statements of cash flows, the Company considers all
highly liquid short-term investments with original maturities of three months or
less to be cash equivalents.
(f) Accounts
Receivable – Trade, Net
Trade
accounts receivable are recorded at the invoiced amount and do not bear
interest. The Company maintains an allowance for doubtful accounts
for estimated losses inherent in its accounts receivable
portfolio. In establishing the required allowance, management
considers historical losses, current receivables aging, and existing industry
and national economic data. The Company reviews its allowance for
doubtful accounts monthly. Past due balances over 90 days and over a
specified amount are reviewed individually for
collectibility. Account balances are charged off against the
allowance after all means of collection have been exhausted and the potential
recovery is remote. The balance in the Company’s allowance for
doubtful accounts related to trade accounts receivable was approximately $1.7
million and $1.5 million at December 31, 2009, and December 31, 2008,
respectively.
(g) Inventories
Materials,
supplies and commodity inventories are valued at the lower of average cost or
market.
(h) Oil
and Natural Gas Properties
Proved
Properties
The
Company accounts for oil and natural gas properties in accordance with the
successful efforts method. In accordance with this method, all
leasehold and development costs of proved properties are capitalized and
amortized on a unit-of-production basis over the remaining life of the proved
reserves and proved developed reserves, respectively.
The
Company evaluates the impairment of its proved oil and natural gas properties on
a field-by-field basis whenever events or changes in circumstances indicate that
the carrying value may not be recoverable. The carrying values of
proved properties are reduced to fair value when the expected undiscounted
future cash flows are less than net book value. The fair values of
proved properties are measured using valuation techniques consistent with the
income approach, converting future cash flows to a single discounted
amount. Significant inputs used to determine the fair values of
proved properties include estimates of: (i) reserves; (ii) future
operating and development costs; (iii) future commodity prices; and
(iv) a market-based weighted average cost of capital rate. The
underlying commodity prices embedded in the Company’s estimated cash flows are
the product of a process that begins with New York Mercantile Exchange (“NYMEX”)
forward curve pricing, adjusted for estimated location and quality
differentials, as well as other factors that Company management believes will
impact realizable prices. Costs of retired, sold or abandoned
properties that constitute a part of an amortization base are charged or
credited, net of proceeds, to accumulated depreciation, depletion and
amortization unless doing so significantly affects the unit-of-production
amortization rate, in which case a gain or loss is recognized
currently. Gains or losses from the disposal of other properties are
recognized currently. Expenditures for maintenance and repairs
necessary to maintain properties in operating condition are expensed as
incurred. Estimated dismantlement and abandonment costs are
capitalized, net of salvage, at their estimated net present value and amortized
on a unit-of-production basis over the remaining life of the related proved
developed reserves. The Company capitalizes interest on borrowed
funds related to its share of costs associated with the drilling and completion
of new oil and natural gas wells. Interest is capitalized only during
the periods in which these assets are
brought
to their intended use. The Company capitalized interest costs from
continuing operations of $0.3 million, $0.9 million and $0.5 million for
the years ended December 31, 2009, December 31, 2008, and
December 31, 2007, respectively.
Unproved
Properties
Costs
related to unproved properties include costs incurred to acquire unproved
reserves. Because these reserves do not meet the definition of proved
reserves, the related costs are not classified as proved
properties. Unproved leasehold costs are capitalized and amortized on
a composite basis if individually insignificant, based on past success,
experience and average lease-term lives. Individually significant
leases are reclassified to proved properties if successful and expensed on a
lease by lease basis if unsuccessful or the lease term
expires. Unamortized leasehold costs related to successful
exploratory drilling are reclassified to proved properties and depleted on a
unit-of-production basis. The Company assesses unproved properties
for impairment quarterly on the basis of its experience in similar situations
and other factors such as the primary lease terms of the properties, the average
holding period of unproved properties, and the relative proportion of such
properties on which proved reserves have been found in the past. The
fair values of unproved properties are measured using valuation techniques
consistent with the income approach, converting future cash flows to a single
discounted amount. Significant inputs used to determine the fair
values of unproved properties include estimates of: (i) reserves;
(ii) future operating and development costs; (iii) future commodity
prices; and (iv) a market-based weighted average cost of capital
rate. The market-based weighted average cost of capital rate is
subjected to additional project-specific risking factors.
Impairment
Based on
the analysis described above, the Company recorded noncash impairment of proved
properties of approximately $30.2 million before and after tax for the year
ended December 31, 2008, which is included in “impairment of goodwill and
long-lived assets” on the consolidated statements of operations. The
Company recorded no impairment of proved properties in continuing operations for
the years ended December 31, 2009, or December 31,
2007. The Company recorded noncash impairment of unproved properties
of approximately $6.3 million and $4.5 million for the years ended
December 31, 2009, and December 31, 2008, which is included in
“exploration costs” on the consolidated statements of operations. The
Company recorded no such impairment for the year ended December 31,
2007.
Exploration
Costs
Geological
and geophysical costs, delay rentals, amortization and impairment of unproved
leasehold costs and costs to drill exploratory wells that do not find proved
reserves are expensed as exploration costs. The costs of any
exploratory wells are carried as an asset if the well finds a sufficient
quantity of reserves to justify its capitalization as a producing well and as
long as the Company is making sufficient progress towards assessing the reserves
and the economic and operating viability of the project.
(i) Other
Property and Equipment
Other
property and equipment includes natural gas gathering systems, pipelines,
buildings, software, data processing and telecommunications equipment, office
furniture and equipment, and other fixed assets. These items are
recorded at cost and are depreciated using the straight-line method based on
expected lives ranging from three to 39 years for the individual asset or group
of assets.
(j) Goodwill
Impairment
Goodwill
represents the excess of the cost of an acquired business over the net amounts
assigned to assets acquired and liabilities assumed. The Company
recorded goodwill in conjunction with its August 2007 acquisition in the
Mid-Continent Deep region, all of which was allocated to the
Mid-Continent
Deep reporting unit. At December 31, 2007, the Company had $64.4
million of goodwill recorded. During the year ended December 31,
2008, the Company recorded adjustments to goodwill related to the sales of
Verden and Woodford Shale assets and post closing adjustments. These
adjustments reduced the balance of goodwill by approximately $44.1
million.
The
Company performed its annual goodwill impairment review in the fourth quarter of
2008. During the fourth quarter of 2008, there were disruptions in
credit markets and reductions in global economic activity that had adverse
impacts on stock markets and commodity prices, both of which contributed to a
decline in the Company’s unit price and corresponding market
capitalization. For most of the fourth quarter of 2008, the Company’s
market capitalization value was below the recorded net book value of its
consolidated balance sheet, including goodwill. Because quoted market
prices for the Company’s reporting units were not available, management used
judgment in estimating the fair value of its reporting units for purposes of
performing the annual goodwill impairment test. All available
information was used to make these fair value determinations, including the
present values of expected future cash flows using prices, costs and discount
factors consistent with those used for internal decision making. The
accounting principles regarding goodwill acknowledge that the observed market
prices of individual trades of a company’s stock (and thus its computed market
capitalization) may not be representative of the fair value of the company as a
whole. Substantial value may arise from the ability to take advantage
of synergies and other benefits that flow from control over another
entity. Consequently, measuring the fair value of a collection of
assets and liabilities that operate together in a controlled entity is different
from measuring the fair value of that entity’s individual common
stock. In most industries, including the Company’s, an acquiring
entity typically is willing to pay more for equity securities that give it a
controlling interest than an investor would pay for a number of equity
securities representing less than a controlling interest; therefore, a control
premium was added to the Company’s fair value calculations. This
control premium was judgmental and based on observations of acquisitions in the
industry.
At
December 31, 2008, based on its impairment analysis, the Company concluded
that impairment of the entire amount of recorded goodwill for the Mid-Continent
Deep reporting unit was required. A $20.3 million before and after
tax noncash impairment of goodwill was recorded during the year ended
December 31, 2008, which is included in “impairment of goodwill and
long-lived assets” on the consolidated statements of operations. The
Company had no goodwill recorded on its consolidated balance sheets at
December 31, 2009, or December 31, 2008.
(k) Revenue
Recognition
Revenues
representative of the Company’s ownership interest in its properties are
presented on a gross basis on the consolidated statements of
operations. Sales of oil, natural gas and NGL are recognized when the
product has been delivered to a custody transfer point, persuasive evidence of a
sales arrangement exists, the rights and responsibility of ownership pass to the
purchaser upon delivery, collection of revenue from the sale is reasonably
assured, and the sales price is fixed or determinable.
The
Company has elected the entitlements method to account for natural gas
production imbalances. Imbalances occur when the Company sells more
or less than its entitled ownership percentage of total natural gas
production. In accordance with the entitlements method, any amount
received in excess of the Company’s share is treated as a
liability. If the Company receives less than its entitled share, the
underproduction is recorded as a receivable. At December 31,
2009, and December 31, 2008, the Company had natural gas production
imbalance receivables of approximately $16.4 million and $17.1 million,
respectively, which are included in “accounts receivable – trade, net” on
the consolidated balance sheets and natural gas production
imbalance
payables of approximately $8.8 million and $9.9 million, respectively, which are
included in “accounts payable and accrued expenses” on the consolidated balance
sheets.
The
Company engages in the purchase, gathering and transportation of third-party
natural gas and subsequently markets such natural gas to independent purchasers
under separate arrangements. As such, the Company separately reports
third-party marketing sales and natural gas marketing
expenses. Marketing margins related to the Company’s production are
included in oil, natural gas and NGL sales.
The
Company generates electricity with excess natural gas, which it uses to serve
certain of its operating facilities in Brea, California. Any excess
electricity is sold to the California wholesale power market. This
revenue is included in “other revenues” on the consolidated statements of
operations.
(l) Restricted
Cash
Restricted
cash of $2.1 million and $1.3 million is included in “other noncurrent assets”
on the consolidated balance sheets at December 31, 2009, and
December 31, 2008, respectively, and represents cash the Company has
deposited into a separate account and designated for asset retirement
obligations in accordance with contractual agreements.
(m) Derivative
Instruments
The
Company uses derivative financial instruments to reduce exposure to fluctuations
in the prices of oil, natural gas and NGL. By removing a significant
portion of the price volatility associated with future production, the Company
expects to mitigate, but not eliminate, the potential effects of variability in
cash flow from operations due to fluctuations in commodity
prices. These transactions are primarily in the form of swap
contracts, put options and collars. In addition, the Company enters
into derivative contracts in the form of interest rate swaps to minimize the
effects of fluctuations in interest rates.
Derivative
instruments (including certain derivative instruments embedded in other
contracts) are recorded at fair value and included on the consolidated balance
sheets as assets or liabilities. The Company did not designate these
contracts as cash flow hedges; therefore, the changes in fair value of these
instruments are recorded in current earnings. The Company determines
the fair value of its derivative financial instruments utilizing pricing models
for significantly similar instruments. Inputs to the pricing models
include publicly available prices and forward price curves generated from a
compilation of data gathered from third parties. See Note 7 and
Note 8 for additional details about the Company’s derivative financial
instruments.
(n) Unit-Based
Compensation
The
Company recognizes expense for unit-based compensation over the requisite
service period, in an amount equal to the fair value of unit-based payments
granted to employees and nonemployee directors. The fair value of
unit-based payments, excluding liability awards, is computed at the date of
grant and is not remeasured. The fair value of liability awards is
remeasured at each reporting date through the settlement date with the change in
fair value recognized as compensation expense over that period. The
Company currently does not have any awards accounted for as liability
awards.
The
Company has made a policy decision to recognize compensation expense for
service-based awards on a straight-line basis over the requisite service period
for the entire award. See Note 5 for additional details about
the Company’s accounting for unit-based compensation.
The
benefit of tax deductions in excess of recognized compensation costs is required
to be reported as financing cash flow, rather than operating cash
flow. This requirement reduces net operating cash flow and increases
net financing cash flow in periods in which such tax benefit
exists. The amount of the Company’s excess tax benefit is reported in
“excess tax benefit from unit-based compensation” on the consolidated statements
of unitholders’ capital.
(o) Deferred
Financing Fees
The
Company incurred legal and bank fees related to the issuance of debt (see
Note 6). At December 31, 2009, and December 31, 2008,
net deferred financing fees of approximately $57.6 million and $11.9 million,
respectively, are included in “other noncurrent assets” on the consolidated
balance sheets. These debt issuance costs are amortized over the life
of the debt agreement. For the years ended December 31, 2009,
December 31, 2008, and December 31, 2007, amortization expense of
$13.7 million, $5.2 million and $1.5 million, respectively, is included in
“interest expense, net of amounts capitalized” on the consolidated statements of
operations.
(p) Fair
Value of Financial Instruments
The
carrying values of the Company’s receivables, payables and Credit Facility (as
defined in Note 6) are estimated to be substantially the same as their fair
values at December 31, 2009, and December 31, 2008. See
Note 6 for fair value disclosures related to the Company’s other
outstanding debt. As noted above, the Company carries its derivative
financial instruments at fair value. See Note 8 for details
about the fair value of the Company’s derivative financial
instruments.
(q) Income
Taxes
The
Company is a limited liability company treated as a partnership for federal and
state income tax purposes, with the exception of the state of Texas, with income
tax liabilities and/or benefits of the Company passed through to
unitholders. As such, with the exception of the state of Texas, it is
not a taxable entity, it does not directly pay federal and state income tax and
recognition has not been given to federal and state income taxes for the
operations of the Company except as described below.
Limited
liability companies are subject to state income taxes in Texas. In
addition, certain of the Company’s subsidiaries are Subchapter C-corporations
subject to federal and state income taxes, which are accounted for using the
asset and liability method. Deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax basis and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date. See Note 14 for detail of amounts recorded in
the consolidated financial statements.
|
(2)
|
Acquisitions,
Divestitures and Discontinued
Operations
|
Acquisitions
– 2009
On
August 31, 2009, and September 30, 2009, the Company completed the
acquisitions of certain oil and natural gas properties located in the Permian
Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian
Corporation (collectively referred to as “Forest”). The results of
operations of these properties have been included in the consolidated financial
statements since these dates. The Company paid $114.4 million in
cash, net of cash received from Forest post-closing, and recorded a receivable
from Forest, resulting in total consideration for the acquisitions of
approximately $113.7 million. The
transactions
were financed with borrowings under the Company’s Credit
Facility. The acquisitions represent a strategic entry into the
Permian Basin for the Company.
The
acquisitions were accounted for under the acquisition method of accounting in
accordance with an accounting standard adopted by the Company effective
January 1, 2009, (see Note 17). Accordingly, the Company
conducted an assessment of net assets acquired and recognized amounts for
identifiable assets acquired and liabilities assumed at their estimated
acquisition date fair values, while transaction and integration costs associated
with the acquisitions were expensed as incurred.
The
following presents the values assigned to the net assets acquired as of the
acquisition dates (in thousands):
|
Assets:
|
||||
|
Current
and other assets
|
$ | 840 | ||
|
Oil
and natural gas properties
|
115,798 | |||
|
Total
assets acquired
|
$ | 116,638 | ||
|
Liabilities:
|
||||
|
Current
liabilities
|
$ | 1,568 | ||
|
Asset
retirement obligations
|
1,350 | |||
|
Total
liabilities assumed
|
$ | 2,918 | ||
|
Net
assets acquired
|
$ | 113,720 | ||
Current
and other assets include vehicles, natural gas imbalance receivables, prepaid ad
valorem taxes, and inventory of oil produced but not yet
sold. Current liabilities include natural gas imbalance payables, ad
valorem taxes payable and environmental liabilities.
The fair
values of oil and natural gas properties and asset retirement obligation
liabilities were measured using valuation techniques that convert future cash
flows to a single discounted amount. Significant inputs to the
valuation of oil and natural gas properties include estimates of:
(i) reserves; (ii) future operating and development costs;
(iii) future commodity prices; and (iv) a market-based weighted
average cost of capital rate. Significant inputs to the valuation of
asset retirement obligation liabilities include estimates of: (i) plug and
abandon costs per well; (ii) remaining life per well; (iii) future
inflation factors; and (iv) a credit-adjusted risk-free interest
rate.
Acquisitions
– 2008 and 2007
Acquisitions
completed prior to January 1, 2009, were accounted for under the purchase
method of accounting. The following is a summary of certain
significant acquisitions completed by the Company during the years ended
December 31, 2008, and December 31, 2007:
|
|
·
|
January 31,
2008, acquisition of certain oil and natural gas properties located
primarily in the Mid-Continent Shallow region, primarily in Oklahoma, from
Lamamco Drilling Company for approximately $542.2
million
|
|
|
·
|
August 31,
2007, acquisition of certain oil and natural gas properties in the
Mid-Continent Deep region, in Oklahoma, Kansas and the Texas Panhandle,
from Dominion Resources, Inc. for approximately
$2.11 billion
|
|
|
·
|
June 12,
2007, acquisition of certain oil and natural gas properties in the
Mid-Continent Shallow region, in the Texas Panhandle, for approximately
$89.7 million
|
|
|
·
|
February 1,
2007, acquisition of certain oil and natural gas properties in the
Mid-Continent Shallow region, in the Texas Panhandle, from Stallion Energy
LLC, acting as general partner for Cavallo Energy, LP, for approximately
$415.6 million
|
Acquisition
– Subsequent Event
On
January 29, 2010, the Company completed the acquisition of certain oil and
natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and
the Permian Basin in Texas and New Mexico, from certain affiliates of Merit
Energy Company (“Merit”) for a contract price of $154.5 million. The
transaction was financed with borrowings under the Company’s Credit Facility and
included a deposit of $15.5 million paid by the Company to Merit in November
2009. At December 31, 2009, this amount is reported in “other
noncurrent assets” on the consolidated balance sheets. The
acquisition provides an addition to the Company’s asset portfolio in the Permian
Basin and Mid-Continent. The initial accounting for the business
combination is not complete pending detailed analyses of the facts and
circumstances that existed as of the acquisition date.
Divestitures
On
December 4, 2008, the Company completed the sale of its deep rights in
certain central Oklahoma acreage, which includes the Woodford Shale interval, to
Devon Energy Production Company, LP. During 2008, the Company
received net proceeds of $153.2 million and the carrying value of net assets
sold was $54.2 million, resulting in a gain on the sale of $99.0 million, which
is recorded in “(gain) loss on sale of assets and other, net” on the
consolidated statements of operations for the year ended December 31,
2008. In the first quarter of 2009, certain post-closing matters were
resolved and the Company recorded a gain of $25.4 million, which is recorded in
“(gain) loss on sale of assets and other, net” on the consolidated statements of
operations for the year ended December 31, 2009.
On
August 15, 2008, the Company completed the sale of certain properties in
the Verden area in Oklahoma to Laredo Petroleum, Inc. During 2008,
the Company received net proceeds equal to the carrying value of net assets sold
of $169.4 million.
On
July 1, 2008, the Company completed the sale of its interests in oil and
natural gas properties located in the Appalachian Basin to XTO Energy,
Inc. During 2008, the Company received net proceeds of $566.5
million. The carrying value of net assets sold was $405.8 million,
resulting in a gain on the sale of $160.7 million In addition, in
March 2008, the Company exited the drilling and service business in the
Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic and
recorded a loss on the sale of $1.6 million. The gain and loss from
these divestitures are recorded in “discontinued operations: (gain) loss on sale
of assets, net of taxes” on the consolidated statements of operations for the
year ended December 31, 2008. The Company used the net proceeds
from all divestitures to reduce indebtedness.
Discontinued
Operations
The
Company’s Appalachian Basin and Mid Atlantic operations (see “Divestitures”
above) have been classified as discontinued operations on the consolidated
statements of operations for all periods presented. The following
summarizes the Appalachian Basin and Mid Atlantic amounts included in “income
(loss) from discontinued operations, net of taxes” on the consolidated
statements of operations:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Total
revenues and other
|
$ | (1,216 | ) | $ | 50,601 | $ | 67,110 | |||||
|
Total
operating expenses
|
(977 | ) | (23,677 | ) | (54,260 | ) | ||||||
|
Interest
expense
|
— | (13,401 | ) | (23,156 | ) | |||||||
|
Income
(loss) from discontinued operations
|
(2,193 | ) | 13,523 | (10,306 | ) | |||||||
|
Income
tax benefit
|
— | 1,391 | 1,215 | |||||||||
|
Income
(loss) from discontinued operations, net
of taxes
|
$ | (2,193 | ) | $ | 14,914 | $ | (9,091 | ) | ||||
Discontinued
operations activity for 2009 primarily represents activity related to
post-closing adjustments. The Company computed interest expense
related to discontinued operations for 2008 and 2007 based on debt required to
be repaid as a result of the disposal transaction.
|
(3)
|
Unitholders’
Capital
|
Public
Offering of Units
In
October 2009, the Company sold 8,625,000 units representing limited liability
company interests at $21.90 per unit ($21.024 per unit, net of underwriting
discount) for net proceeds (after underwriting discount of $7.6 million and
offering expenses of $0.2 million) of approximately $181.1 million, which was
used to reduce indebtedness under the Credit Facility.
In May
2009, the Company sold 6,325,000 units representing limited liability company
interests at $16.25 per unit ($15.60 per unit, net of underwriting discount) for
net proceeds (after underwriting discount of $4.1 million and offering expenses
of $0.4 million) of approximately $98.2 million, which was used to reduce
indebtedness under the Credit Facility.
Unit
Repurchase Plan
In
October 2008, the Board of Directors of the Company authorized the repurchase of
up to $100.0 million of the Company’s outstanding units from time to time on the
open market or in negotiated purchases. During the year ended
December 31, 2009, 123,800 units were repurchased at an average unit price
of $12.99, for a total cost of approximately $1.6 million. During the
year ended December 31, 2008, 1,076,900 units were purchased at an average
unit price of $12.09, for a total cost of approximately $13.0
million. All units were subsequently canceled. At
December 31, 2009, approximately $85.4 million was available for unit
repurchase under the program. The timing and amounts of any such
repurchases will be at the discretion of management, subject to market
conditions and other factors, and in accordance with applicable securities laws
and other legal requirements. The repurchase plan does not obligate
the Company to acquire any specific number of units and may be discontinued at
any time. Units are repurchased at fair market value on the date of
repurchase.
Issuance
and Cancellation of Units
During
the year ended December 31, 2009, the Company purchased 63,031 units for
approximately $1.1 million, in conjunction with units received by the Company
for the payment of minimum withholding taxes due on units issued under its
equity compensation plan (see Note 5). All units were
subsequently canceled.
During
the year ended December 31, 2008, the Company issued 410,000 units in
connection with the termination of certain contractual obligations (equal to a
fair value of approximately $8.7 million). In addition, during the
year ended December 31, 2008, the Company issued 600,000 units in
connection with the acquisition of certain natural gas properties (equal to a
fair value of approximately $14.7 million). During the year ended
December 31, 2008, the Company purchased 94,521 units for approximately
$2.0 million, in conjunction with units received by the Company for the payment
of minimum withholding taxes due on units issued under its equity compensation
plan. All units were subsequently canceled.
During
the year ended December 31, 2007, the Company issued 77,381 units in
connection with the acquisition of royalty interests in certain oil and natural
gas properties. In addition, during the year ended December 31,
2007, the Company purchased 226,561 units for approximately $7.4 million, in
conjunction with units received by the Company for the payment of minimum
withholding taxes due on units issued under its equity compensation
plan. All units were subsequently canceled.
Private
Placements
In August
2007, the Company closed its private placement of $1.5 billion of units to
a group of institutional investors, consisting of 34,997,005 Class D units
at a price of $30.97 per unit, and 12,999,989 units at a price of $32.00 per
unit. Proceeds, net of expenses, were $1.48 billion and were used to
fund the acquisition of oil and natural gas properties. The Class D
units were converted to units on a one-for-one basis in November
2007.
In June
2007, the Company closed its private placement of $260.0 million of units to a
group of institutional investors, consisting of 7,761,194 units at a price of
$33.50 per unit. Proceeds, net of expenses, were $255.2 million
and were used to reduce indebtedness.
In
February 2007, the Company closed its private placement of $360.0 million
of units to a group of institutional investors, consisting of 7,465,946
Class C units at a price of $25.06 per unit, and 6,650,144 units at a price
of $26.00 per unit. Proceeds, net of expenses, were
$353.1 million and were used to fund the acquisition of oil and natural gas
properties. The Class C units were converted into units on a
one-for-one basis in April 2007.
Registration
Statements covering all the units issued through the private placements noted
above were filed and declared effective by the Securities and Exchange
Commission (“SEC”) during December 2007. In December 2007, the
Company was required to pay purchasers in the June 2007 private placement
approximately $0.7 million in liquidated damages as specified in the
registration rights agreement because the registration effectiveness deadline in
the agreement was not achieved. This payment is included in “general
and administrative expenses” on the consolidated statements of operations for
the year ended December 31, 2007.
Distributions
Under the
Agreement, Company unitholders are entitled to receive a quarterly distribution
of available cash to the extent there is sufficient cash from operations after
establishment of cash reserves and payment of fees and
expenses. Distributions paid by the Company are presented on the
consolidated statements of unitholders’ capital. On January 27,
2010, the Company’s Board of Directors declared a cash distribution
of $0.63
per unit with respect to the fourth quarter of 2009. The
distribution, totaling approximately $82.3 million, was paid February 12,
2010, to unitholders of record as of the close of business February 5,
2010.
|
(4)
|
Business
and Credit Concentrations
|
Cash
The
Company maintains its cash in bank deposit accounts, which, at times, may exceed
federally insured amounts. The Company has not experienced any losses
in such accounts. The Company believes it is not exposed to any
significant credit risk on its cash.
Revenue
and Trade Receivables
The
Company has a concentration of customers who are engaged in oil and natural gas
purchasing, transportation and/or refining within the United
States. This concentration of customers may impact the Company’s
overall exposure to credit risk, either positively or negatively, in that the
customers may be similarly affected by changes in economic or other
conditions. The Company’s customers consist primarily of major oil
and natural gas purchasers and the Company generally does not require
collateral, since it has not experienced significant credit losses on such
sales. The Company routinely assesses the recoverability of all
material trade and other receivables to determine collectibility (see
Note 1).
For the
year ended December 31, 2009, the Company’s three largest customers
represented 22%, 18% and 15%, respectively, of the Company’s
sales. For the year ended December 31, 2008, the Company’s three
largest customers represented 21%, 18% and 10%, respectively, of the Company’s
sales. For the year ended December 31, 2007, the Company’s two
largest customers represented 27% and 22%, respectively, of the Company’s
sales.
At
December 31, 2009, trade accounts receivable from three customers accounted
for more than 10% of the Company’s total trade accounts
receivable. At December 31, 2009, trade accounts receivable from
these customers represented approximately 25%, 15% and 15%, respectively, of the
Company’s receivables. At December 31, 2008, trade accounts
receivable from two customers accounted for more than 10% of the Company’s total
trade accounts receivable. At December 31, 2008, trade accounts
receivable from these customers represented approximately 20% and 16%,
respectively, of the Company’s receivables.
|
(5)
|
Unit-Based
Compensation and Other Benefit
Plans
|
Incentive
Plan Summary
The
Amended and Restated Linn Energy, LLC Long-Term Incentive Plan, as amended (the
“Plan”) originally became effective in December 2005. The Plan, which
is administered by the Compensation Committee of the Board of Directors
(“Compensation Committee”), permits the granting of unit grants, unit options,
restricted units, phantom units and unit appreciation rights to employees,
consultants and nonemployee directors under the terms of the
Plan. The unit options and restricted units vest ratably over three
years. The contractual life of unit options is 10
years. Unit awards were issued for the first time in January 2006, in
conjunction with the Company’s IPO.
The Plan
limits the number of units that may be delivered pursuant to awards to 12.2
million units. The Board of Directors and the Compensation Committee
have the right to alter or amend the Plan or any part of the Plan from time to
time, including increasing the number of units that may be granted, subject to
unitholder approval as required by the exchange upon which the units are listed
at that time. However, no change in any outstanding grant may be made
that would materially reduce the benefits to the participant without the consent
of the participant.
Upon
exercise or vesting of an award of units, or an award settled in units, the
Company will issue new units, acquire units on the open market or directly from
any person, or use any combination of the foregoing, at the Compensation
Committee’s discretion. If the Company issues new units upon exercise
or vesting of an award, the total number of units outstanding will
increase. To date, the Company has issued awards of unit grants, unit
options, restricted units and phantom units. The Plan provides for
all of the following types of awards:
Unit Grants A unit
grant is a unit that vests immediately upon issuance.
Unit Options A
unit option is a right to purchase a unit at a specified price at terms
determined by the Compensation Committee. Unit options will have an
exercise price that will not be less than the fair market value of the units on
the date of grant, and in general, will become exercisable over a vesting period
but may accelerate upon a change in control of the Company. If a
grantee’s employment or service relationship terminates for any reason, the
grantee’s unvested unit options will be automatically forfeited unless the
option agreement or the Compensation Committee provides otherwise.
Restricted Units A
restricted unit is a unit that vests over a period of time and that during such
time is subject to forfeiture, and may contain such terms as the Compensation
Committee shall determine. The Company intends the restricted units
under the Plan to serve as a means of incentive compensation for performance and
not primarily as an opportunity to participate in the equity appreciation of its
units. Therefore, Plan participants will not pay any consideration
for the restricted units they receive. If a grantee’s employment or
service relationship terminates for any reason, the grantee’s unvested
restricted units will be automatically forfeited unless the Compensation
Committee or the terms of the award agreement provide otherwise.
Phantom Units/Unit Appreciation
Rights These awards may be settled in units, cash or a
combination thereof. Such grants contain terms as determined by the
Compensation Committee, including the period or terms over which phantom units
vest. If a grantee’s employment or service relationship terminates
for any reason, the grantee’s phantom units or unit appreciation rights will be
automatically forfeited unless, and to the extent, the Compensation Committee or
the terms of the award agreement provide otherwise. While phantom
units require no payment from the grantee, unit appreciation rights will have an
exercise price that will not be less than the fair market value of the units on
the date of grant. At December 31, 2009, the Company had 36,784
phantom units issued and outstanding. To date, the Company has not
issued unit appreciation rights.
Securities
Authorized for Issuance Under the Plan
As of
December 31, 2009, approximately 1.9 million units were issuable under the
Plan pursuant to outstanding award or other agreements, and 6.8 million
additional units were reserved for future issuance under the Plan.
Accounting
for Unit-Based Compensation
Activities
and balances presented in this Note 5 include amounts associated with
discontinued operations for the years ended December 31, 2008, and
December 31, 2007, (see Note 2). The Company recognizes as
expense, beginning at the grant date, the fair value of unit options and other
equity-based compensation issued to employees and nonemployee
directors. The value of the portion of the award that is ultimately
expected to vest is recognized as expense over the requisite service period
using the straight-line method in the Company’s consolidated statements of
operations. A summary of unit-based compensation expenses included on
the consolidated statements of operations is presented below:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
General
and administrative expenses
|
$ | 14,743 | $ | 14,590 | $ | 12,118 | ||||||
|
Lease
operating expenses
|
346 | 109 | — | |||||||||
|
Income
(loss) from discontinued operations, net of taxes
|
― | 978 | 403 | |||||||||
|
Total
unit-based compensation expenses
|
$ | 15,089 | $ | 15,677 | $ | 12,521 | ||||||
|
Income
tax benefit
|
$ | 5,968 | $ | ― | $ | ― | ||||||
Restricted/Unrestricted
Units
The fair
value of unrestricted unit grants and restricted units issued is determined
based on the fair market value of the Company units on the date of
grant. A summary of the status of the nonvested units as of
December 31, 2009, is presented below:
|
Number
of
Nonvested
Units
|
Weighted
Average
Grant-Date
Fair
Value
|
|||||||
|
Nonvested
units at December 31, 2008
|
835,004 | $ | 27.01 | |||||
|
Granted
|
1,115,255 | $ | 16.11 | |||||
|
Vested
|
(409,227 | ) | $ | 27.43 | ||||
|
Forfeited
|
(41,244 | ) | $ | 17.09 | ||||
|
Nonvested
units at December 31, 2009
|
1,499,788 | $ | 19.07 | |||||
The
weighted average grant-date fair value of unrestricted unit grants and
restricted units granted during the years ended December 31, 2008, and
December 31, 2007, was $23.82 and $31.16, respectively.
As of
December 31, 2009, there was approximately $16.1 million of unrecognized
compensation cost related to nonvested restricted units. The cost is
expected to be recognized over a weighted average period of approximately 1.33
years. The total fair value of units that vested was approximately
$11.2 million, $14.0 million and $19.4 million for the years ended
December 31, 2009, December 31, 2008, and December 31, 2007,
respectively.
Changes
in Unit Options and Unit Options Outstanding
The
following provides information related to unit option activity for the year
ended December 31, 2009:
|
Number
of
Units
Underlying
Options
|
Weighted
Average
Exercise
Price
Per
Unit
|
Weighted
Average
Grant-Date
Fair
Value
|
Weighted
Average
Remaining
Contractual
Life
in Years
|
|||||||||||||
|
Outstanding
at December 31, 2008
|
1,590,438 | $ | 24.04 | $ | 3.76 | 8.23 | ||||||||||
|
Granted
|
382,405 | $ | 15.95 | $ | 0.55 | |||||||||||
|
Exercised
|
(25,000 | ) | $ | 19.74 | $ | 3.75 | ||||||||||
|
Outstanding
at December 31, 2009
|
1,947,843 | $ | 22.51 | $ | 3.13 | 7.43 | ||||||||||
|
Exercisable
at December 31, 2009
|
1,147,705 | $ | 24.44 | $ | 4.21 | 6.65 | ||||||||||
The
weighted average grant-date fair value of options granted during the years ended
December 31, 2008, and December 31, 2007, was $2.58 and $4.59,
respectively. The total intrinsic value of options exercised during
the years ended December 31, 2009, December 31, 2008, and
December 31, 2007, was approximately $124,000, $4,000 and $95,000,
respectively. The Company received $0.5 million from the exercise of
options during the year ended December 31, 2009. No options were
forfeited during the year ended December 31, 2009.
As of
December 31, 2009, there was approximately $0.6 million of total
unrecognized compensation cost related to nonvested unit options. The
cost is expected to be recognized over a weighted average period of
approximately 1.04 years. In addition, the exercisable unit options
at December 31, 2009, have an aggregate intrinsic value of approximately
$4.7 million and all outstanding unit options have an aggregate intrinsic value
of approximately $11.5 million. The total fair value of all options
that vested during the years ended December 31, 2009, December 31,
2008, and December 31, 2007, was approximately $1.7 million, $2.1 million
and $1.5 million, respectively. No options expired during the years
ended December 31, 2009, December 31, 2008, or December 31,
2007.
The fair
value of unit-based compensation for unit options was estimated on the date of
grant using a Black-Scholes pricing model based on certain
assumptions. The Company’s determination of the fair value of
unit-based payment awards is affected by the Company’s unit price as well as
assumptions regarding a number of complex and subjective
variables. The Company’s employee unit options have various
restrictions including vesting provisions and restrictions on transfers and
hedging, among others, and often are expected to be exercised prior to their
contractual maturity.
Expected
volatilities used in the estimation of fair value have been determined using
available volatility data for the Company as well as an average of volatility
computations of other identified peer companies in the oil and natural gas
industry. Expected distributions are estimated based on the Company’s
distribution rate at the date of grant. Historical data of the
Company and other identified peer companies is used to estimate expected term
because, due to the limited period of time its equity units have been publicly
traded, the Company does not have sufficient historical exercise data to compute
a reasonable estimation. Forfeitures are estimated using historical
Company data and are revised, if necessary, in subsequent periods if actual
forfeitures differ from estimates. All employees granted awards have
been determined to have similar behaviors for purposes of determining the
expected term used to estimate fair value. The risk-free rate for
periods within the expected term of the unit option is based on the United
States Treasury yield
curve in
effect at the time of grant. The fair values of the unit option
grants were based upon the following assumptions:
|
2009
|
2008 |
2007
|
|||||||||||||||||||||
|
Expected
volatility
|
30.59% | 30.59 | % | – | 34.57 | % | 30.40 | % | – | 35.58 | % | ||||||||||||
|
Expected
distributions
|
15.80 | % | – | 16.79 | % | 10.13 | % | – | 12.32 | % | 6.51 | % | – | 10.67 | % | ||||||||
|
Risk-free
rate
|
1.24 | % | – | 1.91 | % | 2.66 | % | – | 3.41 | % | 3.53 | % | – | 5.18 | % | ||||||||
| Expected term | 5 years | 5 years | 5 years | ||||||||||||||||||||
Although
the fair value of unit option grants is determined, in accordance with
applicable accounting standards, using a Black-Scholes pricing model, that value
may not be indicative of the fair value observed in a willing buyer/willing
seller market transaction.
In
January 2010, the Company granted 638,554 restricted units as part of its annual
review of employee and executive compensation.
Nonemployee
Grants
During
the year ended December 31, 2007, the Company granted an aggregate 150,000
unit warrants to certain individuals in connection with an acquisition
transition services agreement. The unit warrants have an exercise
price of $25.50 per unit warrant, are fully exercisable at December 31,
2009, and expire 10 years from issuance. The Company computed the
fair value of the unit warrants using a Black-Scholes pricing
model. The expense of approximately $1.4 million is included in
“general and administrative expenses” on the consolidated statements of
operations for the year ended December 31, 2007.
Defined
Contribution Plan
The
Company sponsors a 401(k) defined contribution plan for eligible
employees. Company contributions to the 401(k) plan consisted of a
discretionary matching contribution equal to 100% of the first 4% of eligible
compensation contributed by the employee on a before-tax basis for each of the
years in the three year period ending December 31,
2009. Effective January 1, 2010, the Company contribution was
equal to 100% of the first 6% of eligible employee compensation. The
Company contributed approximately $1.7 million, $1.6 million and $0.8 million
during the years ended December 31, 2009, December 31, 2008, and
December 31, 2007, respectively, to the 401(k) plan’s trustee
account. The 401(k) plan funds are held in a trustee account on
behalf of the plan participants.
|
(6)
|
Debt
|
The
following summarizes debt outstanding:
|
December 31,
2009
|
December 31,
2008
|
|||||||||||||||
|
Carrying
Value
|
Fair
Value (1)
|
Carrying
Value
|
Fair
Value (1)
|
|||||||||||||
|
(in
thousands)
|
||||||||||||||||
|
Credit
facility (2)
|
$ | 1,100,000 | $ | 1,100,000 | $ | 1,403,393 | $ | 1,403,393 | ||||||||
|
Senior
notes due 2017, net (3)
|
238,275 | 279,375 | ― | ― | ||||||||||||
|
Senior
notes due 2018, net (4)
|
250,556 | 270,803 | 250,175 | 147,268 | ||||||||||||
|
Less
current maturities
|
― | ― | ― | ― | ||||||||||||
| $ | 1,588,831 | $ | 1,650,178 | $ | 1,653,568 | $ | 1,550,661 | |||||||||
|
|
(1)
|
The
carrying value of the Credit Facility is estimated to be substantially the
same as its fair value. Fair values of the senior notes were
estimated based on prices quoted from third-party financial
institutions.
|
|
|
(2)
|
Variable
interest rate of 2.98% at December 31, 2009, and 2.47% at
December 31, 2008.
|
|
|
(3)
|
Fixed
interest rate of 11.75% and effective interest rate of
12.73%. Amount is net of unamortized discount of approximately
$11.7 million at December 31, 2009.
|
|
|
(4)
|
Fixed
interest rate of 9.875% and effective interest rate of
10.25%. Amount is net of unamortized discount of approximately
$5.4 million and $5.8 million at December 31, 2009, and
December 31, 2008,
respectively.
|
Credit
Facility
On
April 28, 2009, the Company entered into a Fourth Amended and Restated
Credit Agreement (“Credit Facility”), with an initial borrowing base of $1.75
billion and a maturity of August 2012, which amended and restated the Company’s
existing credit facility, which had a maturity of August 2010. The
terms of the Credit Facility required that, upon the issuance of the senior
notes due 2017 in May 2009 (see below) and cancellation of certain commodity
derivatives in July 2009 (see Note 7), the borrowing base be decreased by
approximately $62.5 million and $45.0 million, respectively, to $1.64 billion at
December 31, 2009. At December 31, 2009, available
borrowing capacity was $537.0 million, which includes a $5.5 million reduction
in availability for outstanding letters of credit. In connection with
the amended and restated Credit Facility, during the year ended
December 31, 2009, the Company paid approximately $52.7 million in
financing fees and expenses, which were deferred and will be amortized over the
life of the Credit Facility.
Redetermination
of the borrowing base under the Credit Facility occurs semi-annually, in April
and October, as well as upon the occurrence of certain events, by the lenders in
their sole discretion, based primarily on reserve reports that reflect commodity
prices at such time. Significant declines in prices may result in a
decrease in the borrowing base. The Company’s obligations under the
Credit Facility are secured by mortgages on its oil and natural gas properties
as well as a pledge of all ownership interests in its operating
subsidiaries. The Company is required to maintain the mortgages on
properties representing at least 80% of its properties. Additionally,
the obligations under the Credit Facility are guaranteed by all of the Company’s
material operating subsidiaries and may be guaranteed by any future
subsidiaries.
At the
Company’s election, interest on borrowings under the Credit Facility is
determined by reference to either the London Interbank Offered Rate (“LIBOR”)
plus an applicable margin between 2.50% and 3.25% per annum or the alternate
base rate (“ABR”) plus an applicable margin between 1.00% and 1.75% per
annum. Interest is generally payable quarterly for ABR loans and at
the applicable maturity date for LIBOR loans. The Company is required
to pay a fee of 0.5% per annum on the unused portion of the borrowing base under
the Credit Facility.
The
Credit Facility contains various covenants, substantially similar to those
included prior to the amendment and restatement, which limit the Company’s
ability to: (i) incur indebtedness; (ii) enter into commodity and
interest rate swaps; (iii) grant certain liens; (iv) make certain
loans, acquisitions, capital expenditures and investments; (v) make
distributions other than from available cash; and (vi) merge or
consolidate, or engage in certain asset dispositions, including a sale of all or
substantially all of its assets. The Credit Facility also contains
covenants, substantially similar to those included prior to the amendment and
restatement, which require the Company to maintain adjusted earnings to interest
expense and current liquidity financial ratios. The Company is in
compliance with all financial and other covenants of the Credit
Facility.
Senior
Notes Due 2017
On
May 12, 2009, the Company entered into a purchase agreement with a group of
initial purchasers (“Initial Purchasers”) pursuant to which the Company agreed
to issue $250.0 million in aggregate principal amount of the Company’s senior
notes due 2017 (“2017 Notes”). The 2017 Notes were offered and sold
to the Initial Purchasers and then resold to qualified institutional buyers,
each in transactions exempt from the
registration
requirements of the Securities Act of 1933, as amended (the “Securities
Act”). The Company used the net proceeds (after deducting the Initial
Purchasers’ discounts and offering expenses) of approximately $230.8 million to
reduce indebtedness under its Credit Facility. In connection with the
2017 Notes, the Company incurred financing fees and expenses of approximately
$6.9 million, which will be amortized over the life of the 2017 Notes; the
expense is recorded in “interest expense, net of amounts capitalized” on the
consolidated statements of operations. The $12.3 million discount on
the 2017 Notes will be amortized over the life of the 2017 Notes; the expense is
recorded in “interest expense, net of amounts capitalized” on the consolidated
statements of operations.
The 2017
Notes were issued under an Indenture dated May 18, 2009, (“Indenture”),
mature May 15, 2017, and bear interest at 11.75%. Interest is
payable semi-annually beginning November 15, 2009. The 2017
Notes are general unsecured senior obligations of the Company and are
effectively junior in right of payment to any secured indebtedness of the
Company to the extent of the collateral securing such
indebtedness. Each of the Company’s material subsidiaries guaranteed
the 2017 Notes on a senior unsecured basis. The Indenture provides
that the Company may redeem: (i) on or prior to May 15, 2011, up to
35% of the aggregate principal amount of the 2017 Notes at a redemption price of
111.75% of the principal amount, plus accrued and unpaid interest;
(ii) prior to May 15, 2013, all or part of the 2017 Notes at a
redemption price equal to the principal amount, plus a make-whole premium (as
defined in the Indenture) and accrued and unpaid interest; and (iii) on or
after May 15, 2013, all or part of the 2017 Notes at redemption prices
equal to 105.875% in 2013, 102.938% in 2014 and 100% in 2015 and
thereafter. The Indenture also provides that, if a change of control
(as defined in the Indenture) occurs, the holders have a right to require the
Company to repurchase all or part of the 2017 Notes at a redemption price equal
to 101%, plus accrued and unpaid interest.
The 2017
Notes’ Indenture contains covenants that, among other things, limit the
Company’s ability to: (i) pay distributions on, purchase or redeem the
Company’s units or redeem its subordinated debt; (ii) make investments;
(iii) incur or guarantee additional indebtedness or issue certain types of
equity securities; (iv) create certain liens; (v) sell assets;
(vi) consolidate, merge or transfer all or substantially all of the
Company’s assets; (vii) enter into agreements that restrict distributions
or other payments from the Company’s restricted subsidiaries to the Company;
(viii) engage in transactions with affiliates; and (ix) create
unrestricted subsidiaries. The Company is in compliance with all
financial and other covenants of the 2017 Notes.
In
connection with the issuance and sale of the 2017 Notes, the Company entered
into a Registration Rights Agreement (“Registration Rights Agreement”) with the
Initial Purchasers. Under the Registration Rights Agreement, the
Company agreed to use its reasonable best efforts to file with the SEC and cause
to become effective a registration statement relating to an offer to issue new
notes having terms substantially identical to the 2017 Notes in exchange for
outstanding 2017 Notes. In certain circumstances, the Company may be
required to file a shelf registration statement to cover resales of the 2017
Notes. The Company will not be obligated to file the registration
statements described above if the restrictive legend on the 2017 Notes has been
removed and the 2017 Notes are freely tradable (in each case, other than with
respect to persons that are affiliates of the Company) pursuant to Rule 144
of the Securities Act, as of the 366th day
after the 2017 Notes were issued. If the Company fails to satisfy its
obligations under the Registration Rights Agreement, the Company may be required
to pay additional interest to holders of the 2017 Notes under certain
circumstances.
Senior
Notes Due 2018
On
June 24, 2008, the Company entered into a purchase agreement with a group
of initial purchasers (“Initial Purchasers”) pursuant to which the Company
agreed to issue $255.9 million in aggregate principal amount of the Company’s
senior notes due 2018 (“2018 Notes”). The 2018 Notes were offered and
sold to the Initial Purchasers and then resold to qualified institutional
buyers, each in transactions exempt from the registration requirements of the
Securities Act. The Company used the net proceeds (after deducting
the
Initial
Purchasers’ discounts and offering expenses) of approximately $243.6 million to
repay an outstanding term loan. In connection with the 2018 Notes,
the Company incurred financing fees and expenses of approximately $7.8 million,
which will be amortized over the life of the 2018 Notes; the expense is recorded
in “interest expense, net of amounts capitalized” on the consolidated statements
of operations. The $5.9 million discount on the 2018 Notes will be
amortized over the life of the 2018 Notes; the expense is recorded in “interest
expense, net of amounts capitalized” on the consolidated statements of
operations.
The 2018
Notes were issued under an Indenture dated June 27, 2008, (“Indenture”),
mature July 1, 2018, and bear interest at 9.875%. Interest is
payable semi-annually beginning January 1, 2009. The 2018 Notes
are general unsecured senior obligations of the Company and are effectively
junior in right of payment to any secured indebtedness of the Company to the
extent of the collateral securing such indebtedness. Each of the
Company’s material subsidiaries guaranteed the 2018 Notes on a senior unsecured
basis. The Indenture provides that the Company may redeem:
(i) on or prior to July 1, 2011, up to 35% of the aggregate principal
amount of the 2018 Notes at a redemption price of 109.875% of the principal
amount, plus accrued and unpaid interest; (ii) prior to July 1, 2013,
all or part of the 2018 Notes at a redemption price equal to the principal
amount, plus a make-whole premium (as defined in the Indenture) and accrued and
unpaid interest; and (iii) on or after July 1, 2013, all or part of
the 2018 Notes at redemption prices equal to 104.938% in 2013, 103.292% in 2014,
101.646% in 2015 and 100% in 2016 and thereafter. The Indenture also
provides that, if a change of control (as defined in the Indenture) occurs, the
holders have a right to require the Company to repurchase all or part of the
2018 Notes at a redemption price equal to 101%, plus accrued and unpaid
interest.
The 2018
Notes’ Indenture contains covenants that, among other things, limit the
Company’s ability to: (i) pay distributions on, purchase or redeem the
Company’s units or redeem its subordinated debt; (ii) make investments;
(iii) incur or guarantee additional indebtedness or issue certain types of
equity securities; (iv) create certain liens; (v) sell assets;
(vi) consolidate, merge or transfer all or substantially all of the
Company’s assets; (vii) enter into agreements that restrict distributions
or other payments from the Company’s restricted subsidiaries to the Company;
(viii) engage in transactions with affiliates; and (ix) create
unrestricted subsidiaries. The Company is in compliance with all
financial and other covenants of the 2018 Notes. In June 2009, the
Company instructed the trustee to remove the restrictive legend from the 2018
Notes making them freely tradable (other than with respect to persons that are
affiliates of the Company). This terminated the Company’s obligations
under a registration rights agreement entered into in connection with issuance
of the 2018 Notes.
|
(7)
|
Derivatives
|
Commodity
Derivatives
The
Company sells oil, natural gas and NGL in the normal course of its business and
utilizes derivative instruments to minimize the variability in cash flow due to
commodity price movements. The Company enters into derivative
instruments such as swap contracts, put options and collars to economically
hedge its forecasted oil, natural gas and NGL sales. Oil puts are
also used to economically hedge NGL sales. The Company did not
designate these contracts as cash flow hedges; therefore, the changes in fair
value of these instruments are recorded in current earnings. See
Note 8 for fair value disclosures about oil and natural gas commodity
derivatives.
The
following table summarizes open positions as of December 31, 2009, and
represents, as of such date, derivatives in place through December 31,
2013, on annual production volumes:
|
Year
2010
|
Year
2011
|
Year
2012
|
Year
2013
|
|||||||||||||
|
Natural
gas positions:
|
||||||||||||||||
|
Fixed
price swaps:
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
39,566 | 31,901 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 8.90 | $ | 9.50 | $ | — | $ | — | ||||||||
|
Puts:
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
6,960 | 6,960 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 8.50 | $ | 9.50 | $ | — | $ | — | ||||||||
|
PEPL
puts: (1)
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
10,634 | 13,259 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 7.85 | $ | 8.50 | $ | — | $ | — | ||||||||
|
Total:
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
57,160 | 52,120 | — | — | ||||||||||||
|
Average
price ($/MMBtu)
|
$ | 8.66 | $ | 9.25 | $ | — | $ | — | ||||||||
|
Oil
positions:
|
||||||||||||||||
|
Fixed
price swaps: (2)
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
2,150 | 2,073 | 732 | 730 | ||||||||||||
|
Average
price ($/Bbl)
|
$ | 90.00 | $ | 90.00 | $ | 100.00 | $ | 100.00 | ||||||||
|
Puts:
(3)
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
2,250 | 2,352 | — | — | ||||||||||||
|
Average
price ($/Bbl)
|
$ | 110.00 | $ | 75.00 | $ | — | $ | — | ||||||||
|
Collars:
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
250 | 276 | — | — | ||||||||||||
|
Average
floor price ($/Bbl)
|
$ | 90.00 | $ | 90.00 | $ | — | $ | — | ||||||||
|
Average
ceiling price ($/Bbl)
|
$ | 112.00 | $ | 112.25 | $ | — | $ | — | ||||||||
|
Total:
|
||||||||||||||||
|
Hedged
volume (MBbls)
|
4,650 | 4,701 | 732 | 730 | ||||||||||||
|
Average
price ($/Bbl)
|
$ | 99.68 | $ | 82.50 | $ | 100.00 | $ | 100.00 | ||||||||
|
Natural
gas basis differential positions:
|
||||||||||||||||
|
PEPL
basis swaps: (1)
|
||||||||||||||||
|
Hedged
volume (MMMBtu)
|
43,166 | 35,541 | 34,066 | 31,700 | ||||||||||||
|
Hedged
differential ($/MMBtu)
|
$ | (0.97 | ) | $ | (0.96 | ) | $ | (0.95 | ) | $ | (1.01 | ) | ||||
|
|
(1)
|
Settle
on the Panhandle Eastern Pipeline (“PEPL”) spot price of natural gas to
hedge basis differential associated with natural gas production in the
Mid-Continent Deep and Mid-Continent Shallow
regions.
|
|
|
(2)
|
As
presented in the table above, the Company has outstanding fixed price oil
swaps on 2,000 Bbls per day at a price of $100.00 per Bbl for the years
ending December 31, 2012, and December 31, 2013. The
Company has derivative contracts that extend the swaps for each of the
years ending December 31, 2014, December 31, 2015, and
December 31, 2016, if the counterparties determine that the strike
prices are in-the-money on a designated date in each respective preceding
year. The extension for each year is exercisable without
respect to the other years.
|
|
|
(3)
|
The
Company utilizes oil puts to hedge revenues associated with its NGL
production.
|
Settled
derivatives on natural gas production for the year ended December 31, 2009,
included a volume of 51,880 MMMBtu at an average contract price of
$8.32. Settled derivatives on oil and NGL production for the year
ended December 31, 2009, included a volume of 4,530 MBbls at an average
contract price of
$102.21. The
natural gas derivatives are settled based on the closing NYMEX future price of
natural gas or on the published PEPL spot price of natural gas on the settlement
date, which occurs on the third day preceding the production
month. The oil derivatives are settled based on the month’s average
daily NYMEX price of light oil and settlement occurs on the final day of the
production month.
In
February 2010, the Company entered into fixed price oil swaps on an additional
5,250 Bbls per day at a price of $100.00 per Bbl for the years ending
December 31, 2012, and December 31, 2013. The Company has
derivative contracts that extend the swaps for each of the years ending
December 31, 2014, December 31, 2015, and December 31, 2016, if
the counterparties determine that the strike prices are in-the-money on a
designated date in each respective preceding year. The extension for
each year is exercisable without respect to the other years.
Interest
Rate Swaps
The
Company has entered into interest rate swap agreements based on LIBOR to
minimize the effect of fluctuations in interest rates. If LIBOR is
lower than the fixed rate in the contract, the Company is required to pay the
counterparty the difference, and conversely, the counterparty is required to pay
the Company if LIBOR is higher than the fixed rate in the
contract. The Company did not designate the interest rate swap
agreements as cash flow hedges; therefore, the changes in fair value of these
instruments are recorded in current earnings. See Note 8 for
fair value disclosures about interest rate swaps.
The
following presents the settlement terms of the interest rate swaps at
December 31, 2009:
|
Year
2010
|
Year
2011
|
Year
2012
|
Year
2013 (1)
|
|||||||||||||
|
(dollars
in thousands)
|
||||||||||||||||
|
Notional
amount
|
$ | 1,212,000 | $ | 1,212,000 | $ | 1,212,000 | $ | 1,212,000 | ||||||||
|
Fixed
rate
|
3.85 | % | 3.85 | % | 3.85 | % | 3.85 | % | ||||||||
|
|
(1)
|
Actual
settlement term is through January 6,
2014.
|
Outstanding
Notional Amounts
The
following presents the outstanding notional amounts and maximum number of months
outstanding of derivative instruments:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Outstanding
notional amounts of natural gas contracts (MMMBtu)
|
109,280 | 196,756 | ||||||
|
Maximum
number of months natural gas contracts outstanding
|
24 | 48 | ||||||
|
Outstanding
notional amounts of oil contracts (MBbls)
|
10,813 | 21,229 | ||||||
|
Maximum
number of months oil contracts outstanding
|
48 | 72 | ||||||
|
Outstanding
notional amount of interest rate swaps (in thousands)
|
$ | 1,212,000 | $ | 1,212,000 | ||||
|
Maximum
number of months interest rate swaps outstanding
|
48 | 24 | ||||||
Balance
Sheet Presentation
The
Company’s commodity derivatives and interest rate swap derivatives are presented
on a net basis in “derivative instruments” on the consolidated balance
sheets. The following summarizes the fair value of derivatives
outstanding on a gross basis:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Assets:
|
||||||||
|
Commodity
derivatives
|
$ | 549,879 | $ | 977,847 | ||||
|
Interest
rate swaps
|
2,603 | ― | ||||||
| $ | 552,482 | $ | 977,847 | |||||
|
Liabilities:
|
||||||||
|
Commodity
derivatives
|
$ | 192,573 | $ | 119,124 | ||||
|
Interest
rate swaps
|
69,644 | 82,422 | ||||||
| $ | 262,217 | $ | 201,546 | |||||
By using
derivative instruments to economically hedge exposures to changes in commodity
prices and interest rates, the Company exposes itself to credit risk and market
risk. Credit risk is the failure of the counterparty to perform under
the terms of the derivative contract. When the fair value of a
derivative contract is positive, the counterparty owes the Company, which
creates credit risk. The Company’s counterparties are participants or
affiliates of participants in its Credit Facility (see Note 6), which is
secured by the Company’s oil and natural gas reserves; therefore, the Company is
not required to post any collateral. The Company does not require
collateral from its counterparties. The maximum amount of loss due to
credit risk that the Company would incur if its counterparties failed completely
to perform according to the terms of the contracts, based on the gross fair
value of financial instruments, was approximately $552.5 million at
December 31, 2009. The Company minimizes the credit risk in
derivative instruments by: (i) limiting its exposure to any single
counterparty; (ii) entering into derivative instruments only with
counterparties that meet the Company’s minimum credit quality standard, or have
a guarantee from an affiliate that meets the Company’s minimum credit quality
standard; and (iii) monitoring the creditworthiness of the Company’s
counterparties on an ongoing basis. In accordance with the Company’s
standard practice, its commodity and interest rate derivatives are subject to
counterparty netting under agreements governing such derivatives and therefore
the risk of such loss is somewhat mitigated.
Gain
(Loss) on Derivatives
Gains and
losses on derivatives are reported on the consolidated statements of operations
in “gain (loss) on oil and natural gas derivatives” and “gain (loss) on interest
rate swaps” and include realized and unrealized gains
(losses). Realized gains (losses), excluding canceled derivatives,
represent amounts related to the settlement of derivative instruments, and for
commodity derivatives, are aligned with the underlying
production. Unrealized gains (losses) represent the change in fair
value of the derivative instruments and are noncash items.
The
following presents the Company’s reported gains and losses on derivative
instruments:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Realized
gains (losses):
|
||||||||||||
|
Commodity
derivatives
|
$ | 400,968 | $ | 9,408 | $ | 37,250 | ||||||
|
Interest
rate swaps
|
(42,881 | ) | (16,036 | ) | 1,467 | |||||||
|
Canceled
derivatives
|
48,977 | (81,358 | ) | ― | ||||||||
| $ | 407,064 | $ | (87,986 | ) | $ | 38,717 | ||||||
|
Unrealized
gains (losses):
|
||||||||||||
|
Commodity
derivatives
|
$ | (591,379 | ) | $ | 734,732 | $ | (382,787 | ) | ||||
|
Interest
rate swaps
|
16,588 | (50,638 | ) | (29,548 | ) | |||||||
| $ | (574,791 | ) | $ | 684,094 | $ | (412,335 | ) | |||||
|
Total
gains (losses):
|
||||||||||||
|
Commodity
derivatives
|
$ | (141,374 | ) | $ | 662,782 | $ | (345,537 | ) | ||||
|
Interest
rate swaps
|
(26,353 | ) | (66,674 | ) | (28,081 | ) | ||||||
| $ | (167,727 | ) | $ | 596,108 | $ | (373,618 | ) | |||||
During
the year ended December 31, 2009, the Company canceled (before the
contract settlement date) derivative contracts on estimated future oil and
natural gas production resulting in realized net gains of approximately $49.0
million. Of this amount, realized net gains of approximately $44.8
million, along with an incremental premium payment of approximately $48.8
million, were used to reposition the Company’s commodity derivative portfolio in
July 2009 when the Company canceled oil and natural gas derivative contracts for
years 2012 through 2014 to raise prices for oil and natural gas derivative
contracts in years 2010 and 2011.
During
the year ended December 31, 2008, the Company canceled (before the contract
settlement date) derivative contracts on estimated future natural gas production
resulting in realized losses of approximately $81.4 million. The
future natural gas production under the canceled contracts primarily related to
properties in the Appalachian Basin and Verden areas (see
Note 2).
|
(8)
|
Fair
Value Measurements on a Recurring
Basis
|
The
Company accounts for its commodity and interest rate derivatives at fair value
(see Note 7) on a recurring basis. The fair value of derivative
instruments is determined utilizing pricing models for significantly similar
instruments. Inputs to the pricing models include publicly available
prices and forward price curves generated from a compilation of data gathered
from third parties. Assumed credit risk adjustments, based on
published credit ratings, public bond yield spreads and credit default swap
spreads, are applied to the Company’s commodity and interest rate
derivatives.
Fair
Value Hierarchy
In
accordance with applicable accounting standards, the Company has categorized its
financial instruments, based on the priority of inputs to the valuation
technique, into a three-level fair value hierarchy. The fair value
hierarchy gives the highest priority to quoted prices in active markets for
identical assets or liabilities (Level 1) and the lowest priority to
unobservable inputs (Level 3).
Financial
assets and liabilities recorded on the consolidated balance sheets are
categorized based on the inputs to the valuation techniques as
follows:
|
|
Level 1
|
Financial
assets and liabilities for which values are based on unadjusted quoted
prices for identical assets or liabilities in an active market that
management has the ability to
access.
|
|
|
Level 2
|
Financial
assets and liabilities for which values are based on quoted prices in
markets that are not active or model inputs that are observable either
directly or indirectly for substantially the full term of the asset or
liability (commodity derivatives and interest rate
swaps).
|
|
|
Level 3
|
Financial
assets and liabilities for which values are based on prices or valuation
techniques that require inputs that are both unobservable and significant
to the overall fair value measurement. These inputs reflect
management’s own assumptions about the assumptions a market participant
would use in pricing the asset or
liability.
|
When the
inputs used to measure fair value fall within different levels of the hierarchy
in a liquid environment, the level within which the fair value measurement is
categorized is based on the lowest level input that is significant to the fair
value measurement in its entirety. The Company conducts a review of
fair value hierarchy classifications on a quarterly basis. Changes in
the observability of valuation inputs may result in a reclassification for
certain financial assets or liabilities.
The
following presents the fair value hierarchy for assets and liabilities measured
at fair value on a recurring basis:
|
Fair
Value Measurements on a Recurring Basis
December 31,
2009
|
||||||||||||
|
Level
2
|
Netting (1)
|
Total
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Assets:
|
||||||||||||
|
Commodity
derivatives
|
$ | 549,879 | $ | (154,666 | ) | $ | 395,213 | |||||
|
Interest
rate swaps
|
$ | 2,603 | $ | (2,603 | ) | $ | — | |||||
|
Liabilities:
|
||||||||||||
|
Commodity
derivatives
|
$ | 192,573 | $ | (154,666 | ) | $ | 37,907 | |||||
|
Interest
rate swaps
|
$ | 69,644 | $ | (2,603 | ) | $ | 67,041 | |||||
|
|
(1)
|
Represents
counterparty netting under agreements governing such
derivatives.
|
|
(9)
|
Other
Property and Equipment
|
Other
property and equipment consists of the following:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Natural
gas compression plant and pipeline
|
$ | 88,765 | $ | 87,133 | ||||
|
Buildings
and leasehold improvements
|
9,213 | 7,734 | ||||||
|
Vehicles
|
7,005 | 5,840 | ||||||
|
Drilling
and other equipment
|
1,313 | 1,566 | ||||||
|
Furniture
and office equipment
|
11,929 | 8,338 | ||||||
|
Land
|
642 | 848 | ||||||
| 118,867 | 111,459 | |||||||
|
Less
accumulated depreciation
|
(23,583 | ) | (13,171 | ) | ||||
| $ | 95,284 | $ | 98,288 | |||||
|
(10)
|
Asset
Retirement Obligations
|
Asset
retirement obligations associated with retiring tangible long-lived assets, are
recognized as a liability in the period in which a legal obligation is incurred
and becomes determinable and are included in “other noncurrent liabilities” on
the consolidated balance sheets. Accretion expense is included in
“depreciation, depletion and amortization” on the consolidated statements of
operations. The fair value of additions to the asset retirement
obligation liability is estimated using valuation techniques that convert future
cash flows to a single discounted amount. Significant inputs to the
valuation include estimates of: (i) plug and abandon costs per well based
on existing regulatory requirements; (ii) remaining life per well; (iii)
future inflation factors (2.0% for each of the years in the three-year period
ended December 31, 2009); and (iv) a credit-adjusted risk-free interest
rate (average of 9.6%, 7.8% and 7.0% for the years ended December 31, 2009,
December 31, 2008, and December 31, 2007, respectively).
Inherent
in the fair value calculation of asset retirement obligations are numerous
assumptions and judgments including, in addition to those noted above, the
ultimate settlement amounts, timing of settlement, and changes in legal,
regulatory, environmental and political environments. To the extent
future revisions to these assumptions impact the fair value of the existing
asset retirement obligation liability, a corresponding adjustment is made to the
asset balance.
The
following presents a reconciliation of the asset retirement obligation
liability:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Asset
retirement obligations at beginning of year
|
$ | 28,922 | $ | 29,073 | ||||
|
Liabilities
added from acquisitions
|
1,350 | 5,398 | ||||||
|
Liabilities
added from drilling
|
66 | 541 | ||||||
|
Liabilities
associated with assets sold
|
― | (8,020 | ) | |||||
|
Current
year accretion expense
|
2,324 | 1,967 | ||||||
|
Settlements
|
(577 | ) | (37 | ) | ||||
|
Revision
of estimates
|
1,050 | ― | ||||||
|
Asset
retirement obligations at end of year
|
$ | 33,135 | $ | 28,922 | ||||
|
(11)
|
Commitments
and Contingencies
|
On
September 15, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) filed
a voluntary petition for reorganization under Chapter 11 of the United
States Bankruptcy Code (“Chapter 11”) with the United States Bankruptcy Court
for the Southern District of New York (the “Court”). On
October 3, 2008, Lehman Brothers Commodity Services Inc. (“Lehman Commodity
Services”) also filed a voluntary petition for reorganization under Chapter 11
with the Court. At December 31, 2009, and December 31,
2008, the Company had a net receivable of approximately $6.7 million from Lehman
Commodity Services for canceled derivative contracts, which is included in
“other current assets” on the consolidated balance sheets. The value
of the receivable was estimated based on market expectations. The
Company is pursuing various legal remedies to protect its interests and believes
that the ultimate disposition of this matter will not have a material adverse
effect on its business, financial position, results of operations or
liquidity.
From time
to time, the Company is a party to various legal proceedings or is subject to
industry rulings that could bring rise to claims in the ordinary course of
business. The Company is not currently a party to any litigation or
pending claims that it believes would have a material adverse effect on its
business, financial position, results of operations or liquidity.
|
(12)
|
Earnings
Per Unit
|
Effective
January 1, 2009, the Company adopted an accounting standard that requires
unvested restricted units to be included in the computation of earnings per unit
under the two-class method. The adoption required retrospective
adjustment of all prior period earnings per unit data. The impact of
the adoption was a reduction to income from continuing operations per unit –
diluted and net income per unit – diluted, of $0.05 per unit for the year ended
December 31, 2008. There was no impact for the year ended
December 31, 2007.
Basic
earnings per unit is computed by dividing net earnings attributable to
unitholders by the weighted average number of units outstanding during each
period. Diluted earnings per unit is computed by adjusting the
average number of units outstanding for the dilutive effect, if any, of unit
equivalents. The Company uses the treasury stock method to determine
the dilutive effect.
The
following table provides a reconciliation of the numerators and denominators of
the basic and diluted per unit computations for income (loss) from continuing
operations:
|
Income
(Loss)
(Numerator)
|
Units
(Denominator)
|
Per
Unit
Amount
|
||||||||||
| (in thousands) | ||||||||||||
|
Year
ended December 31, 2009:
|
||||||||||||
|
Loss
from continuing operations:
|
||||||||||||
|
Allocated
to units
|
$ | (295,841 | ) | |||||||||
|
Allocated
to unvested restricted units
|
— | |||||||||||
| $ | (295,841 | ) | ||||||||||
|
Loss
per unit:
|
||||||||||||
|
Basic
loss per unit
|
119,307 | $ | (2.48 | ) | ||||||||
|
Dilutive
effect of unit equivalents
|
— | — | ||||||||||
|
Diluted
loss per unit
|
119,307 | $ | (2.48 | ) | ||||||||
|
Year
ended December 31, 2008:
|
||||||||||||
|
Income
from continuing operations:
|
||||||||||||
|
Allocated
to units
|
$ | 825,657 | ||||||||||
|
Allocated
to unvested restricted units
|
(5,610 | ) | ||||||||||
| $ | 820,047 | |||||||||||
|
Income
per unit:
|
||||||||||||
|
Basic
income per unit
|
114,140 | $ | 7.18 | |||||||||
|
Dilutive
effect of unit equivalents
|
18 | — | ||||||||||
|
Diluted
income per unit
|
114,158 | $ | 7.18 | |||||||||
|
Year
ended December 31, 2007:
|
||||||||||||
|
Loss
from continuing operations:
|
||||||||||||
|
Allocated
to units
|
$ | (356,194 | ) | |||||||||
|
Allocated
to unvested restricted units
|
— | |||||||||||
| $ | (356,194 | ) | ||||||||||
|
Loss
per unit:
|
||||||||||||
|
Basic
loss per unit
|
68,916 | $ | (5.17 | ) | ||||||||
|
Dilutive
effect of unit equivalents
|
— | — | ||||||||||
|
Diluted
loss per unit
|
68,916 | $ | (5.17 | ) | ||||||||
Basic
units outstanding excludes the effect of weighted average anti-dilutive unit
equivalents related to 2.1 million, 1.7 million and 1.2 million unit options and
warrants for the years ended December 31, 2009, December 31, 2008, and
December 31, 2007, respectively. All equivalent units were
anti-dilutive for the years ended December 31, 2009, and December 31,
2007.
|
(13)
|
Operating
Leases
|
The
Company leases office space and other property and equipment under lease
agreements expiring on various dates through 2019. The Company
recognized expense under operating leases of approximately $3.6 million, $3.2
million and $1.2 million for the years ended December 31, 2009,
December 31, 2008, and December 31, 2007,
respectively.
As of
December 31, 2009, future minimum lease payments were as follows (in
thousands):
|
2010
|
$ | 3,954 | ||
|
2011
|
4,084 | |||
|
2012
|
3,727 | |||
|
2013
|
3,251 | |||
|
2014
|
3,275 | |||
|
Thereafter
|
11,674 | |||
| $ | 29,965 |
|
(14)
|
Income
Taxes
|
The
Company is a limited liability company treated as a partnership for federal and
state income tax purposes, with the exception of the state of Texas, with income
tax liabilities and/or benefits of the Company passed through to
unitholders. Limited liability companies are subject to state income
taxes in Texas. As such, with the exception of the state of Texas, it
is not a taxable entity, it does not directly pay federal and state income tax
and recognition has not been given to federal and state income taxes for the
operations of the Company, except as set forth in the tables below.
The
Company’s taxable income or loss, which may vary substantially from the net
income or net loss reported in the consolidated statements of operations, is
includable in the federal and state income tax returns of each
unitholder. The aggregate difference in the basis of net assets for
financial and tax reporting purposes cannot be readily determined as the Company
does not have access to information about each unitholder’s tax attributes in
the Company.
Certain
of the Company’s subsidiaries are Subchapter C-corporations subject to
federal and state income taxes. Income tax benefit (expense) from
continuing operations consisted of the following:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Current
taxes:
|
||||||||||||
|
Federal
|
$ | (1,063 | ) | $ | (1,184 | ) | $ | (1,355 | ) | |||
|
State
|
(678 | ) | (1,528 | ) | (283 | ) | ||||||
|
Deferred
taxes:
|
||||||||||||
|
Federal
|
5,307 | — | (3,066 | ) | ||||||||
|
State
|
655 | — | (84 | ) | ||||||||
| $ | 4,221 | $ | (2,712 | ) | $ | (4,788 | ) | |||||
As of
December 31, 2009, the Company’s taxable entities had approximately $3.0
million of net operating loss carryforwards for federal income tax purposes,
which will begin expiring in 2025.
Income
tax benefit (expense) differed from amounts computed by applying the federal
income tax rate of 35% to pre-tax income (loss) from continuing operations as a
result of the following:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Federal
statutory rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State,
net of federal tax benefit
|
— | 0.1 | (0.1 | ) | ||||||||
|
Income
or loss excluded from nontaxable entities
|
(34.3 | ) | (34.9 | ) | (35.3 | ) | ||||||
|
Nondeductible
compensation
|
— | — | (0.3 | ) | ||||||||
|
Other
items
|
0.7 | 0.1 | (0.7 | ) | ||||||||
|
Effective
rate
|
1.4 | % | 0.3 | % | (1.4 | )% | ||||||
Significant
components of the deferred tax assets and liabilities were as
follows:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Deferred
tax assets:
|
||||||||
|
Net
operating loss carryforwards
|
$ | 1,175 | $ | 2,767 | ||||
|
Unit-based
compensation
|
7,166 | 5,617 | ||||||
|
Other
|
1,924 | 897 | ||||||
|
Valuation
allowance
|
(1,223 | ) | (7,132 | ) | ||||
|
Total
deferred tax assets
|
9,042 | 2,149 | ||||||
|
Deferred
tax liabilities:
|
||||||||
|
Property
and equipment principally due to differences in
depreciation
|
(2,284 | ) | (2,149 | ) | ||||
|
Other
|
(322 | ) | — | |||||
|
Total
deferred tax liabilities
|
(2,606 | ) | (2,149 | ) | ||||
|
Net
deferred tax assets (liabilities)
|
$ | 6,436 | $ | — | ||||
Net
deferred tax assets and liabilities were classified in the consolidated balance
sheets as follows:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Other
current assets – deferred tax assets
|
$ | 5,372 | $ | — | ||||
|
Deferred
tax assets
|
$ | 3,670 | $ | 2,149 | ||||
|
Deferred
tax liabilities
|
(2,606 | ) | (2,149 | ) | ||||
|
Other
noncurrent assets
|
$ | 1,064 | $ | — | ||||
In
assessing the realizability of deferred tax assets, management considers whether
it is more likely than not that some portion or all of the deferred tax assets
will not be realized. The ultimate realization of deferred tax assets
is dependent upon the generation of future taxable income during the periods in
which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future
taxable income and tax planning strategies in making this
assessment. Based upon the level of historical taxable income and
projections for future taxable income over the periods in which the deferred tax
assets are deductible, management believes it is more likely than not that
the
Company
will realize the benefits of the majority of these deductible differences at
December 31, 2009. The Company has recorded a valuation
allowance against certain deferred tax assets. The amount of deferred
tax assets considered realizable could be reduced in the future if estimates of
future taxable income during the carryforward period are reduced.
In
accordance with the applicable accounting standard, the Company recognizes only
the impact of income tax positions that, based on their merits, are more likely
than not to be sustained upon audit by a taxing authority. In
evaluating its current tax positions in order to identify any material uncertain
tax positions, the Company developed a policy in identifying uncertain tax
positions that considers support for each tax position, industry standards, tax
return disclosures and schedules, and the significance of each
position. It is the Company’s policy to recognize interest and
penalties, if any, related to unrecognized tax benefits in income tax
expense. The Company had no material uncertain tax positions at
December 31, 2009, or December 31, 2008.
|
(15)
|
Related
Party Transactions
|
Lehman
Holdings
During
the year ended December 31, 2008 (through July 3, 2008), and the year
ended December 31, 2007, on an aggregate basis, a group of certain direct
or indirect wholly owned subsidiaries of Lehman Holdings owned over 10% of the
Company’s outstanding units. As such, Lehman Holdings was considered
a related party during that time frame. Lehman Holdings’ subsidiaries
provided certain services to the Company, including participation in the
Company’s Credit Facility, offering of 2018 Notes (see Note 6), sale of
Appalachian Basin assets (see Note 2) and sale of commodity derivative
instruments (see Note 7), which were all consummated on terms equivalent to
those that prevail in arm’s-length transactions. A reference to
“Lehman” hereafter in this footnote refers to Lehman Holdings or one or more of
its subsidiaries, as applicable. See Note 11 for details about
Lehman’s Chapter 11 filings.
During
the year ended December 31, 2008 (through July 3), the Company paid
Lehman interest on borrowings of approximately $2.2 million and financing fees
of approximately $1.8 million. During the year ended
December 31, 2007, the Company paid Lehman interest on borrowings of
approximately $2.1 million and financing fees of approximately $0.1
million.
During
the year ended December 31, 2007, in conjunction with its private
placements of units, the Company paid Lehman underwriting fees of approximately
$13.5 million. Lehman was a participant in the private placements and
the Company received approximately $378.7 million of proceeds from Lehman in
relation to these transactions during the year ended December 31,
2007.
During
the year ended December 31, 2008 (through July 3), the Company paid
distributions on units to Lehman of approximately $18.5
million. During the year ended December 31, 2007, the Company
paid distributions on units to Lehman of approximately $15.2
million. During the year ended December 31, 2008 (through
July 3), the Company paid Lehman approximately $18.8 million, on settled
commodity derivative contracts. During the year ended
December 31, 2007, Lehman paid the Company approximately $8.2 million on
settled commodity derivative contracts. During the year ended
December 31, 2008 (through July 3), the Company purchased
approximately $1.3 million of deal contingent commodity swap contracts from
Lehman. In addition, during the year ended December 31, 2007,
the Company paid Lehman approximately $226.3 million for commodity derivative
contracts.
Other
During
the years ended December 31, 2008, and December 31, 2007, the Company
made payments of approximately $0.3 million and $0.2 million to a company owned
by a member of its Board of Directors. The payments primarily reflect
purchases of natural gas and are primarily included in “natural gas marketing
expenses” on the consolidated statements of operations. The
transactions were consummated on terms equivalent to those that prevail in
arm’s-length transactions.
Eric P.
Linn, brother of the Company’s Executive Chairman, served as President of one of
the Company’s wholly owned subsidiaries. Effective March 31, 2008,
Mr. Linn’s employment with the Company terminated and he executed a Severance
Agreement and Release. During the year ended December 31, 2008, the
Company made payments of approximately $0.2 million to Mr. Linn under the
Severance Agreement and Release. The payments are included in “income
(loss) from discontinued operations, net of taxes” on the consolidated
statements of operations. The transaction was consummated on terms
equivalent to those that prevail in arm’s-length transactions.
|
(16)
|
Supplemental
Disclosures to the Consolidated Balance Sheets and Consolidated Statements
of Cash Flows
|
“Other
accrued liabilities” reported on the consolidated balance sheets include the
following:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Accrued
compensation
|
$ | 14,378 | $ | 11,366 | ||||
|
Accrued
interest
|
18,332 | 14,232 | ||||||
|
Other
|
1,212 | 1,565 | ||||||
| $ | 33,922 | $ | 27,163 | |||||
Supplemental
disclosures to the consolidated statements of cash flows are presented
below:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
payments for interest, net of amounts capitalized
|
$ | 73,861 | $ | 94,958 | $ | 57,348 | ||||||
|
Cash
payments for income taxes
|
$ | 1,282 | $ | 452 | $ | ― | ||||||
|
Noncash
investing activities:
|
||||||||||||
|
In
connection with the acquisition of oil and natural gas properties,
liabilities were assumed as follows:
|
||||||||||||
|
Fair
value of assets acquired
|
$ | 117,717 | $ | 602,858 | $ | 2,710,417 | ||||||
|
Cash
paid
|
(115,285 | ) | (593,412 | ) | (2,649,965 | ) | ||||||
|
Receivable
from seller
|
636 | ― | ― | |||||||||
|
Liabilities
assumed
|
$ | 3,068 | $ | 9,446 | $ | 60,452 | ||||||
|
Noncash
financing activities:
|
||||||||||||
|
Units
issued in connection with the acquisition of oil and natural gas
properties
|
$ | ― | $ | 23,455 | $ | 2,600 | ||||||
|
(17)
|
Recently
Issued Pronouncements
|
Codification
In June
2009, the Financial Accounting Standards Board (“FASB”) approved the FASB
Accounting Standards Codification (“Codification” or “ASC”), effective for
financial statements for interim or annual reporting periods ending after
September 15, 2009. The Codification is the single source of
authoritative nongovernmental GAAP, superseding existing FASB, American
Institute of Certified Public Accountants, Emerging Issues Task Force and
related literature. References herein to prior GAAP standards that
were used to create the Codification have been replaced or supplemented with
references to the relevant section of the Codification and are identified as
“FASB ASC” or “ASC Update.”
Accounting
Standards
In August
2009, the FASB issued ASC Update 2009-5, “Fair Value Measurements and
Disclosures (Topic 820) – Measuring Liabilities at Fair Value,”
which includes amendments to Subtopic 820-10, “Fair Value Measurements and
Disclosures – Overall,” for the fair value measurement
of liabilities and provides clarification that in circumstances in which a
quoted price in an active market for the identical liability is not available,
an entity is required to measure fair value using one or more of the techniques
provided for in this update, including the quoted price of the liability when
traded as an asset. The guidance in this update is effective for
interim and annual periods ending after September 30, 2009, and the Company
adopted it effective October 1, 2009. The adoption did not have a
material impact on the Company’s results of operations or financial
position.
In May
2009, the FASB issued FASB ASC 855, “Subsequent Events,” and in
February 2010, the FASB issued ASC Update 2010-09, “Subsequent Events (Topic 855)
– Amendments to Certain Recognition and Disclosure Requirements,” which
establishes standards of accounting for and disclosure of events that occur
after the balance sheet date but before financial statements are
issued. Under this standard, entities that file or furnish financial
statements with the SEC, such as the Company, are required to use an issued date
in evaluating subsequent events. This standard, as updated, is
effective February 24, 2010, and the Company adopted it at that
date. The adoption did not have a material impact on the Company’s
results of operations or financial position.
In April
2009, the FASB issued three related standards to clarify the application of FASB
ASC 820 “Fair Value
Measurements and Disclosures,” to fair value measurements in the current
economic environment, modify the recognition of other-than-temporary impairments
of debt securities, and require companies to disclose the fair value of
financial instruments in interim periods. The final standards are
effective for interim and annual periods ending after June 15, 2009, and
the Company adopted the new standards effective June 30,
2009. The adoption did not have a material impact on the Company’s
results of operations or financial position. The three related
standards are as follows:
FASB
ASC 820-10-65-4, “Transition Related to FASB Staff
Position FAS 157-4, Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly,” provides guidance on how to determine
the fair value of assets and liabilities under FASB ASC 820 in the current
economic environment and reemphasizes that the objective of a fair value
measurement remains the price that would be received to sell an asset or paid to
transfer a liability at the measurement date.
FASB
ASC 320-10-65-1, “Transition Related to FSP FAS 115-2
and FAS 124-2, Recognition and Presentation of Other-Than-Temporary
Impairments,” modifies the requirements for recognizing
other-than-temporarily impaired debt securities and significantly changes the
existing impairment model for such securities. It also modifies the
presentation of other-than-temporary impairment
losses
and increases the frequency of and expands already required disclosures about
other-than-temporary impairment for debt and equity securities.
FASB
ASC 825-10-65-1, “Transition Related to FSP FAS 107-1
and APB 28-1, Interim Disclosures about Fair Value of Financial
Instruments,” requires disclosures of the fair value of financial
instruments within the scope of FASB ASC 825, “Financial Instruments,” in
interim financial statements, adding to the current requirement to make those
disclosures in annual financial statements. It also requires that
companies disclose the method or methods and significant assumptions used to
estimate the fair value of financial instruments and a discussion of changes, if
any, in the method or methods and significant assumptions during the
period.
FASB
ASC 805, “Business
Combinations,” issued in December 2007, with additional guidance issued
in April 2009, requires an acquiring entity to recognize all assets acquired and
liabilities assumed at fair value with limited exceptions. Assets
acquired and liabilities assumed that arise from contingencies are to be
recognized at fair value if fair value can be reasonably
estimated. If fair value of such an asset or liability cannot be
reasonably estimated, the asset or liability should generally be recognized in
accordance with FASB ASC 450, “Contingencies.” This
standard changes the accounting treatment for certain specific items, including
acquisition costs, which are expensed as incurred, and also includes new
disclosure requirements. This standard applies prospectively to
business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period on or after December 15,
2008. The Company adopted this standard effective January 1,
2009, (see Note 2).
FASB
ASC 820, “Fair Value
Measurements and Disclosures,” issued in September 2006, provides
guidance for using fair value to measure assets and liabilities. This
standard applies whenever other standards require (or permit) assets or
liabilities to be measured at fair value and clarifies that for items that are
not actively traded, such as certain kinds of derivatives, fair value should
reflect the price in a transaction with a market participant, including an
adjustment for risk, not just the mark-to-market value. The Company
adopted the provisions of this standard related to financial assets and
liabilities and nonfinancial assets and liabilities measured on a recurring
basis effective January 1, 2008, and related to nonfinancial assets and
liabilities measured on a nonrecurring basis effective January 1, 2009,
(see Note 2 and Note 10). There was no impact from the
adoption related to items measured on a nonrecurring basis.
The
following discussion and analysis should be read in conjunction with the
“Consolidated Financial Statements” and “Notes to Consolidated Financial
Statements,” which are included in this Annual Report on Form 10-K in
Item 8. “Financial Statements and Supplementary Data.” The
Company’s Appalachian Basin and Mid Atlantic operations have been classified as
discontinued operations on the consolidated statements of operations for all
periods presented (see Note 2). Unless otherwise indicated,
information presented in the following supplemental oil and natural gas data has
been recast to present continuing operations separately from discontinued
operations.
|
(A)
|
Modernization
of Oil and Natural Gas Reporting
Requirements
|
Effective
for fiscal years ending on or after December 31, 2009, the SEC approved
revisions designed to modernize reserve reporting requirements for oil and
natural gas companies. In addition, effective for the same period,
the FASB issued ASC Update 2010-03, “Extractive Activities – Oil and Gas
(Topic 932) – Oil and Gas Reserve Estimation and Disclosures,” to provide
consistency with the new SEC rules. The most significant amendments
to the requirements include the following:
|
|
·
|
commodity
prices – economic producibility of reserves estimated using the average
price during the 12-month period, determined as an unweighted average of
the first-day-of-the-month price for each month, unless prices are defined
by contractual arrangements, excluding escalations based upon future
conditions;
|
|
|
·
|
disclosure
of unproved reserves – probable and possible reserves may be disclosed
separately on a voluntary basis;
|
|
|
·
|
proved
undeveloped reserve guidelines – reserves may be classified as proved
undeveloped if there is a high degree of confidence that the quantities
will be recovered;
|
|
|
·
|
reserve
estimation using new technologies – reserves may be estimated through the
use of reliable technology in addition to flow tests and production
history; and
|
|
|
·
|
nontraditional
resources – the
definition of oil and natural gas producing activities were expanded and
focus on the marketable product rather than the method of
extraction.
|
The
Company adopted the new requirements effective December 31,
2009. The adoption did not have a material impact on the Company’s
results of operations or financial position. The impact of adoption
due to the estimation of reserves using the average price instead of the
year-end price was a material reduction in estimated quantity and value of
reserves at December 31, 2009, of approximately 195 Bcfe, or $1.50
billion. There were no other significant impacts of
adoption.
|
(B)
|
Costs
Incurred in Oil and Natural Gas Property Acquisition, Exploration and
Development Activities
|
Costs
incurred in oil and natural gas property acquisition, exploration and
development, whether capitalized or expensed, are presented below:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Property
acquisition costs: (1)
|
||||||||||||
|
Proved
|
$ | 115,929 | $ | 595,795 | $ | 2,422,983 | ||||||
|
Unproved
|
947 | 4,111 | 148,284 | |||||||||
|
Exploration
costs
|
337 | — | — | |||||||||
|
Development
costs
|
140,892 | 332,557 | 189,466 | |||||||||
|
Total
costs incurred
|
$ | 258,105 | $ | 932,463 | $ | 2,760,733 | ||||||
|
Costs
incurred – continuing operations
|
$ | 258,105 | $ | 900,256 | $ | 2,674,439 | ||||||
|
Costs
incurred – discontinued operations
|
$ | — | $ | 32,207 | $ | 86,294 | ||||||
|
|
(1)
|
See
Note 2 for details about the Company’s
acquisitions.
|
105
LINN
ENERGY, LLC
SUPPLEMENTAL
OIL AND NATURAL GAS DATA (Unaudited) - Continued
|
(C)
|
Oil
and Natural Gas Capitalized Costs
|
Aggregate
capitalized costs related to oil, natural gas and NGL production activities with
applicable accumulated depletion and amortization are presented
below:
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Proved
properties:
|
||||||||
|
Leasehold
acquisition
|
$ | 3,398,292 | $ | 3,278,155 | ||||
|
Development
|
600,436 | 460,730 | ||||||
|
Unproved
properties
|
78,067 | 92,298 | ||||||
| 4,076,795 | 3,831,183 | |||||||
|
Less
accumulated depletion and amortization
|
(463,413 | ) | (278,805 | ) | ||||
| $ | 3,613,382 | $ | 3,552,378 | |||||
|
(D)
|
Results
of Oil and Natural Gas Producing
Activities
|
The
results of operations for oil, natural gas and NGL producing activities
(excluding corporate overhead and interest costs) are presented
below:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
and other:
|
||||||||||||
|
Oil,
natural gas and natural gas liquid sales
|
$ | 408,219 | $ | 755,644 | $ | 255,927 | ||||||
|
Gain
(loss) on oil and natural gas derivatives
|
(141,374 | ) | 662,782 | (345,537 | ) | |||||||
| 266,845 | 1,418,426 | (89,610 | ) | |||||||||
|
Production
costs:
|
||||||||||||
|
Lease
operating expenses
|
132,647 | 115,402 | 41,946 | |||||||||
|
Transportation
expenses
|
18,202 | 17,597 | 5,575 | |||||||||
|
Production
and ad valorem taxes
|
28,687 | 59,598 | 20,295 | |||||||||
| 179,536 | 192,597 | 67,816 | ||||||||||
|
Other
costs:
|
||||||||||||
|
Exploration
costs
|
7,169 | 7,603 | 4,053 | |||||||||
|
Depletion
and amortization
|
191,314 | 185,857 | 64,857 | |||||||||
|
Impairment
of goodwill and long-lived assets
|
― | 50,505 | ― | |||||||||
|
Texas
margin tax expense
|
490 | 920 | ― | |||||||||
|
(Gain)
loss on sale of assets and other, net
|
(25,710 | ) | (99,050 | ) | ― | |||||||
| 173,263 | 145,835 | 68,910 | ||||||||||
|
Results
of continuing operations
|
$ | (85,954 | ) | $ | 1,079,994 | $ | (226,336 | ) | ||||
|
Results
of discontinued operations
|
$ | (238 | ) | $ | 190,915 | $ | 19,111 | |||||
There is
no federal tax provision included in the results above because the Company’s
subsidiaries subject to federal tax do not own any of the Company’s oil and
natural gas interests. Limited liability companies are subject to
state income taxes in Texas (see Note 14). Discontinued
operations activity for 2009 primarily represents activity related to
post-closing adjustments for the sale of properties in the Appalachian Basin
(see Note 2).
106
LINN
ENERGY, LLC
SUPPLEMENTAL
OIL AND NATURAL GAS DATA (Unaudited) - Continued
|
(E)
|
Proved
Oil, Natural Gas and NGL Reserves
|
The
proved reserves of oil, natural gas and NGL of the Company have been prepared by
the independent engineering firm DeGolyer and MacNaughton. In
accordance with revised SEC regulations (see Note A), reserves at
December 31, 2009, were estimated using the average price during the
12-month period, determined as an unweighted average of the
first-day-of-the-month price for each month, unless prices are defined by
contractual arrangements, excluding escalations based upon future
conditions. In accordance with SEC regulations, reserves for all
prior years were estimated using year-end prices. An analysis of the
change in estimated quantities of oil, natural gas and NGL reserves, all of
which are located within the United States, is shown below:
|
Year
Ended December 31, 2009
|
||||||||||||||||
|
Natural
Gas
(MMcf)
|
Oil
(MBbls)
|
NGL
(MBbls)
|
Total
(MMcfe)
|
|||||||||||||
|
Proved
developed and undeveloped reserves:
|
||||||||||||||||
|
Beginning
of year
|
851,232 | 84,144 | 50,722 | 1,660,428 | ||||||||||||
|
Revisions
of previous estimates
|
(69,347 | ) | 10,868 | 3,904 | 19,280 | |||||||||||
|
Purchase
of minerals in place
|
6,825 | 8,757 | 386 | 61,684 | ||||||||||||
|
Extensions,
discoveries and other additions
|
31,479 | 1,648 | 1,508 | 50,416 | ||||||||||||
|
Production
|
(45,710 | ) | (3,287 | ) | (2,358 | ) | (79,580 | ) | ||||||||
|
End
of year
|
774,479 | 102,130 | 54,162 | 1,712,228 | ||||||||||||
|
Proved
developed reserves:
|
||||||||||||||||
|
Beginning
of year
|
585,071 | 61,884 | 29,600 | 1,133,976 | ||||||||||||
|
End
of year
|
549,218 | 77,878 | 33,898 | 1,219,876 | ||||||||||||
|
Proved
undeveloped reserves:
|
||||||||||||||||
|
Beginning
of year
|
266,161 | 22,260 | 21,122 | 526,452 | ||||||||||||
|
End
of year
|
225,261 | 24,252 | 20,264 | 492,352 | ||||||||||||
|
Year
Ended December 31, 2008
|
||||||||||||||||||||||||
|
Natural
Gas
(MMcf)
|
Oil
(MBbls)
|
NGL
(MBbls)
|
Total
Continuing
Operations
(MMcfe)
|
Total
Discontinued
Operations
(MMcfe)
|
Total
(MMcfe)
|
|||||||||||||||||||
|
Proved
developed and undeveloped reserves:
|
||||||||||||||||||||||||
|
Beginning
of year
|
833,390 | 54,469 | 43,124 | 1,418,947 | 197,160 | 1,616,107 | ||||||||||||||||||
|
Revisions
of previous estimates
|
(122,138 | ) | (16,223 | ) | (1,427 | ) | (228,036 | ) | — | (228,036 | ) | |||||||||||||
|
Purchase
of minerals in place
|
72,817 | 46,099 | 3,121 | 368,136 | 5,340 | 373,476 | ||||||||||||||||||
|
Sales
of minerals in place
|
(47,467 | ) | (270 | ) | (11 | ) | (49,154 | ) | (199,711 | ) | (248,865 | ) | ||||||||||||
|
Extensions,
discoveries and other additions
|
159,836 | 3,207 | 8,167 | 228,083 | 1,757 | 229,840 | ||||||||||||||||||
|
Production
|
(45,206 | ) | (3,138 | ) | (2,252 | ) | (77,548 | ) | (4,546 | ) | (82,094 | ) | ||||||||||||
|
End
of year
|
851,232 | 84,144 | 50,722 | 1,660,428 | — | 1,660,428 | ||||||||||||||||||
|
Proved
developed reserves:
|
||||||||||||||||||||||||
|
Beginning
of year
|
616,109 | 42,509 | 25,546 | 1,024,440 | 147,702 | 1,172,142 | ||||||||||||||||||
|
End
of year
|
585,071 | 61,884 | 29,600 | 1,133,976 | — | 1,133,976 | ||||||||||||||||||
|
Proved
undeveloped reserves:
|
||||||||||||||||||||||||
|
Beginning
of year
|
217,281 | 11,960 | 17,578 | 394,507 | 49,458 | 443,965 | ||||||||||||||||||
|
End
of year
|
266,161 | 22,260 | 21,122 | 526,452 | — | 526,452 | ||||||||||||||||||
107
LINN
ENERGY, LLC
SUPPLEMENTAL
OIL AND NATURAL GAS DATA (Unaudited) - Continued
|
Year
Ended December 31, 2007
|
||||||||||||||||||||||||
|
Natural
Gas
(MMcf)
|
Oil
(MBbls)
|
NGL
(MBbls)
|
Total
Continuing
Operations
(MMcfe)
|
Total
Discontinued
Operations
(MMcfe)
|
Total
(MMcfe)
|
|||||||||||||||||||
|
Proved
developed and undeveloped reserves:
|
||||||||||||||||||||||||
|
Beginning
of year
|
77,275 | 29,639 | — | 255,109 | 198,957 | 454,066 | ||||||||||||||||||
|
Revisions
of previous estimates
|
(7,375 | ) | 6,555 | 162 | 32,923 | (18,392 | ) | 14,531 | ||||||||||||||||
|
Purchase
of minerals in place
|
714,026 | 17,823 | 41,741 | 1,071,409 | 23,558 | 1,094,967 | ||||||||||||||||||
|
Sales
of minerals in place
|
— | — | — | — | (1,511 | ) | (1,511 | ) | ||||||||||||||||
|
Extensions,
discoveries and other additions
|
67,994 | 1,694 | 2,213 | 91,437 | 3,196 | 94,633 | ||||||||||||||||||
|
Production
|
(18,530 | ) | (1,242 | ) | (992 | ) | (31,931 | ) | (8,648 | ) | (40,579 | ) | ||||||||||||
|
End
of year
|
833,390 | 54,469 | 43,124 | 1,418,947 | 197,160 | 1,616,107 | ||||||||||||||||||
|
Proved
developed reserves:
|
||||||||||||||||||||||||
|
Beginning
of year
|
49,383 | 24,304 | — | 195,206 | 118,851 | 314,057 | ||||||||||||||||||
|
End
of year
|
616,109 | 42,509 | 25,546 | 1,024,440 | 147,702 | 1,172,142 | ||||||||||||||||||
|
Proved
undeveloped reserves:
|
||||||||||||||||||||||||
|
Beginning
of year
|
27,892 | 5,335 | — | 59,903 | 80,106 | 140,009 | ||||||||||||||||||
|
End
of year
|
217,281 | 11,960 | 17,578 | 394,507 | 49,458 | 443,965 | ||||||||||||||||||
The
tables above include changes in estimated quantities of oil and NGL reserves
shown in Mcf equivalents at a rate of one barrel per six Mcf.
The
Company sold its interests in properties located in the Appalachian Basin during
the year ended December 31, 2008, and the “total discontinued operations”
column in the tables above reports the information for these
properties. Other property sales during the year ended
December 31, 2008, include the sale of assets in the Verden area of
Oklahoma. See Note 2 for additional details about the Company’s
acquisitions and divestitures.
Proved
reserves increased by approximately 52 Bcfe, to approximately 1,712 Bcfe for the
year ended December 31, 2009, from 1,660 Bcfe for the year ended
December 31, 2008. The year ended December 31, 2009,
includes 19 Bcfe in positive revisions of previous estimates, due primarily to
higher asset performance, which contributed approximately 38 Bcfe, most
significantly related to well reactivations and waterflood optimization work in
the Mid-Continent Shallow region. These positive revisions were
partially offset by 19 Bcfe in negative revisions primarily due to decreases in
natural gas prices. Two acquisitions during the year ended
December 31, 2009, increased proved reserves by approximately 62
Bcfe. In addition, extensions and discoveries, primarily from 72
productive wells drilled during the year, contributed approximately 50 Bcfe to
the increase in proved reserves.
Proved
reserves related to continuing operations increased by approximately 241 Bcfe,
to approximately 1,660 Bcfe for the year ended December 31, 2008, from
1,419 Bcfe for the year ended December 31, 2007. Substantially
all of the 228 Bcfe in negative revisions of previous estimates was due to
decreases in oil and natural gas prices. Four acquisitions during the
year ended December 31, 2008, increased proved reserves by approximately
368 Bcfe. In addition, extensions and discoveries, primarily from 304
productive wells drilled during the year, contributed approximately 228 Bcfe to
the increase in proved reserves. The sale of properties located in
the Verden area of Oklahoma decreased proved reserves by approximately 49
Bcfe.
Proved
reserves related to continuing operations increased by approximately 1,164 Bcfe,
to approximately 1,419 Bcfe for the year ended December 31, 2007, from 255
Bcfe for the year ended December 31, 2006. Six acquisitions
during the year ended December 31, 2007, increased proved reserves by
approximately 1,071 Bcfe. In addition, extensions and discoveries,
primarily from 136 productive wells drilled during the year, contributed
approximately 91 Bcfe to the increase in proved reserves.
108
LINN
ENERGY, LLC
SUPPLEMENTAL
OIL AND NATURAL GAS DATA (Unaudited) - Continued
|
(F)
|
Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein Relating
to Proved Reserves
|
Information
with respect to the standardized measure of discounted future net cash flows
relating to proved reserves is summarized below. Future cash inflows
are computed by applying applicable prices relating to the Company’s proved
reserves to the year-end quantities of those reserves. Future
production, development, site restoration and abandonment costs are derived
based on current costs assuming continuation of existing economic
conditions. There are no future income tax expenses because the
Company is not subject to federal income taxes. Limited liability
companies are subject to state income taxes in Texas; however, these amounts are
not material (see Note 14).
|
December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Future
estimated revenues
|
$ | 10,093,876 | $ | 8,261,234 | $ | 12,565,382 | ||||||
|
Future
estimated production costs
|
(4,200,091 | ) | (3,410,684 | ) | (3,052,847 | ) | ||||||
|
Future
estimated development costs
|
(816,577 | ) | (896,625 | ) | (582,890 | ) | ||||||
|
Future
net cash flows
|
5,077,208 | 3,953,925 | 8,929,645 | |||||||||
|
10%
annual discount for estimated timing of cash flows
|
(3,353,926 | ) | (2,529,558 | ) | (5,754,798 | ) | ||||||
|
Standardized
measure of discounted future net cash flows – continuing
operations
|
$ | 1,723,282 | $ | 1,424,367 | $ | 3,174,847 | ||||||
|
Standardized
measure of discounted future net cash flows – discontinued
operations
|
$ | — | $ | — | $ | 283,392 | ||||||
|
Representative
NYMEX prices: (1)
|
||||||||||||
|
Natural
gas (MMBtu)
|
$ | 3.87 | $ | 5.71 | $ | 6.80 | ||||||
|
Oil
(Bbl)
|
$ | 61.05 | $ | 39.22 | $ | 95.92 | ||||||
|
|
(1)
|
In
accordance with SEC regulations, reserves at December 31, 2009, were
estimated using the average price during the 12-month period, determined
as an unweighted average of the first-day-of-the-month price for each
month, unless prices are defined by contractual arrangements, excluding
escalations based upon future conditions. In accordance with
SEC regulations, reserves for all prior years were estimated using
year-end prices.
|
109
LINN
ENERGY, LLC
SUPPLEMENTAL
OIL AND NATURAL GAS DATA (Unaudited) - Continued
The
following summarizes the principal sources of change in the standardized measure
of discounted future net cash flows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Sales
and transfers of oil, natural gas and NGL produced during the
period
|
$ | (228,683 | ) | $ | (563,047 | ) | $ | (188,111 | ) | |||
|
Changes
in estimated future development costs
|
54,141 | 32,006 | 6,271 | |||||||||
|
Net
change in sales and transfer prices and production costs related to future
production
|
254,036 | (2,837,262 | ) | 81,654 | ||||||||
|
Purchase
of minerals in place
|
128,779 | 1,066,615 | 2,438,178 | |||||||||
|
Sale
of minerals in place
|
― | (102,437 | ) | ― | ||||||||
|
Extensions,
discoveries, and improved recovery
|
25,888 | 383,017 | 172,989 | |||||||||
|
Previously
estimated development costs incurred during the period
|
52,699 | 76,150 | 69,221 | |||||||||
|
Net
change due to revisions in quantity estimates
|
23,672 | (69,044 | ) | 56,154 | ||||||||
|
Accretion
of discount
|
142,437 | 317,485 | 29,876 | |||||||||
|
Changes
in production rates and other
|
(154,054 | ) | (53,963 | ) | 209,855 | |||||||
|
Change
– continuing operations
|
$ | 298,915 | $ | (1,750,480 | ) | $ | 2,876,087 | |||||
|
Change
– discontinued operations
|
$ | ― | $ | (283,392 | ) | $ | 29,892 | |||||
The data
presented should not be viewed as representing the expected cash flow from, or
current value of, existing proved reserves since the computations are based on a
large number of estimates and arbitrary assumptions. Reserve
quantities cannot be measured with precision and their estimation requires many
judgmental determinations and frequent revisions. The required
projection of production and related expenditures over time requires further
estimates with respect to pipeline availability, rates of demand and
governmental control. Actual future prices and costs are likely to be
substantially different from the current prices and costs utilized in the
computation of reported amounts. Any analysis or evaluation of the
reported amounts should give specific recognition to the computational methods
utilized and the limitations inherent therein.
The
following discussion and analysis should be read in conjunction with the
“Consolidated Financial Statements” and “Notes to Consolidated Financial
Statements,” which are included in this Annual Report on Form 10-K in
Item 8. “Financial Statements and Supplementary Data.”
|
(A)
|
Quarterly
Financial Data
|
|
Quarters
Ended
|
||||||||||||||||
|
March
31
|
June
30
|
September
30
|
December 31
|
|||||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||||||
|
2009:
|
||||||||||||||||
|
Oil,
natural gas and natural gas liquid sales
|
$ | 79,864 | $ | 91,906 | $ | 102,989 | $ | 133,460 | ||||||||
|
Gain
(loss) on oil and natural gas derivatives
|
$ | 161,315 | $ | (232,775 | ) | $ | (14,065 | ) | $ | (55,849 | ) | |||||
|
Total
revenues and other
|
$ | 242,661 | $ | (139,045 | ) | $ | 90,425 | $ | 79,108 | |||||||
|
Total
expenses (1)
|
$ | 121,576 | $ | 117,295 | $ | 116,339 | $ | 120,884 | ||||||||
|
(Gain)
loss on sale of assets and other, net
|
$ | (26,711 | ) | $ | (5 | ) | $ | 1,999 | $ | 119 | ||||||
|
Income
(loss) from continuing operations
|
$ | 121,287 | $ | (268,701 | ) | $ | (82,462 | ) | $ | (65,965 | ) | |||||
|
Income
(loss) from discontinued operations, net of taxes (2)
|
$ | (1,886 | ) | $ | 229 | $ | (1,247 | ) | $ | 553 | ||||||
|
Net
income (loss)
|
$ | 119,401 | $ | (268,472 | ) | $ | (83,709 | ) | $ | (65,412 | ) | |||||
|
Income
(loss) per unit – continuing operations:
|
||||||||||||||||
|
Basic
|
$ | 1.06 | $ | (2.31 | ) | $ | (0.69 | ) | $ | (0.52 | ) | |||||
|
Diluted
|
$ | 1.06 | $ | (2.31 | ) | $ | (0.69 | ) | $ | (0.52 | ) | |||||
|
Income
(loss) per unit – discontinued operations:
|
||||||||||||||||
|
Basic
|
$ | (0.02 | ) | $ | 0.01 | $ | (0.01 | ) | $ | 0.01 | ||||||
|
Diluted
|
$ | (0.02 | ) | $ | 0.01 | $ | (0.01 | ) | $ | 0.01 | ||||||
|
Net
income (loss) per unit:
|
||||||||||||||||
|
Basic
|
$ | 1.04 | $ | (2.30 | ) | $ | (0.70 | ) | $ | (0.51 | ) | |||||
|
Diluted
|
$ | 1.04 | $ | (2.30 | ) | $ | (0.70 | ) | $ | (0.51 | ) | |||||
|
|
(1)
|
Includes
the following expenses: lease operating, transportation, natural gas
marketing, general and administrative, exploration, bad debt,
depreciation, depletion and amortization, and taxes, other than income
taxes.
|
|
|
(2)
|
Includes
discontinued operations’ gain (loss) on sale of assets, net of
taxes.
|
|
Quarters
Ended
|
||||||||||||||||
|
March
31
|
June
30
|
September
30
|
December 31
|
|||||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||||||
|
2008:
|
||||||||||||||||
|
Oil,
natural gas and natural gas liquid sales (1)
|
$ | 175,872 | $ | 255,586 | $ | 240,634 | $ | 83,552 | ||||||||
|
Gain
(loss) on oil and natural gas derivatives
|
$ | (268,794 | ) | $ | (870,804 | ) | $ | 845,818 | $ | 956,562 | ||||||
|
Total
revenues and other
|
$ | (89,627 | ) | $ | (610,983 | ) | $ | 1,091,660 | $ | 1,043,981 | ||||||
|
Total
expenses (2)
|
$ | 104,274 | $ | 118,521 | $ | 132,889 | $ | 180,848 | ||||||||
|
(Gain)
loss on sale of assets and other, net
|
$ | ― | $ | ― | $ | ― | $ | (98,763 | ) | |||||||
|
Income
(loss) from continuing operations
|
$ | (258,959 | ) | $ | (725,381 | ) | $ | 921,943 | $ | 888,054 | ||||||
|
Income
(loss) from discontinued operations, net of taxes (3)
|
$ | (400 | ) | $ | 13,239 | $ | 160,668 | $ | 452 | |||||||
|
Net
income (loss)
|
$ | (259,359 | ) | $ | (712,142 | ) | $ | 1,082,611 | $ | 888,506 | ||||||
|
Income
(loss) per unit – continuing operations: (4)
|
||||||||||||||||
|
Basic
|
$ | (2.28 | ) | $ | (6.35 | ) | $ | 8.01 | $ | 7.72 | ||||||
|
Diluted
|
$ | (2.28 | ) | $ | (6.35 | ) | $ | 8.01 | $ | 7.72 | ||||||
|
Income
per unit – discontinued operations: (4)
|
||||||||||||||||
|
Basic
|
$ | ― | $ | 0.12 | $ | 1.39 | $ | ― | ||||||||
|
Diluted
|
$ | ― | $ | 0.12 | $ | 1.39 | $ | ― | ||||||||
|
Net
income (loss) per unit: (4)
|
||||||||||||||||
|
Basic
|
$ | (2.28 | ) | $ | (6.23 | ) | $ | 9.40 | $ | 7.72 | ||||||
|
Diluted
|
$ | (2.28 | ) | $ | (6.23 | ) | $ | 9.40 | $ | 7.72 | ||||||
|
|
(1)
|
Oil,
natural gas and natural gas liquid sales decreased during the quarter
ended December 31, 2008, primarily due to lower commodity
prices. In addition, nonoperated accrual estimate revisions
associated with prior quarters of approximately $14.1 million contributed
to the decrease.
|
|
|
(2)
|
Includes
the following expenses: lease operating, transportation, natural gas
marketing, general and administrative, exploration, bad debt,
depreciation, depletion and amortization, impairment of goodwill and
long-lived assets, and taxes, other than income
taxes.
|
|
|
(3)
|
Includes
discontinued operations’ gain (loss) on sale of assets, net of
taxes.
|
|
|
(4)
|
Effective
January 1, 2009, the Company adopted an accounting standard requiring
unvested restricted units to be included in the computation of earnings
per unit under the two-class method. The adoption required
retrospective adjustment of all prior period earnings per unit
data. The impact of the adoption was a reduction to income from
continuing operations per unit – diluted and net income per
unit – diluted, of $0.04 per unit and $0.06 per unit, respectively,
for the quarter ended September 30, 2008, and $0.04 for the quarter
ended December 31, 2008. There was no impact for the
quarters ended March 31, 2008, or June 30,
2008.
|
None.
Evaluation
of Disclosure Controls and Procedures
The
Company maintains disclosure controls and procedures that are designed to ensure
that information required to be disclosed in the Company’s reports under the
Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded,
processed, summarized and reported within the time periods specified in the
SEC’s rules and forms, and that such information is accumulated and communicated
to management, including the Company’s Chief Executive Officer and Chief
Financial Officer, and the Company’s Audit Committee of the Board of Directors,
as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating the disclosure controls and
procedures, management recognizes that any controls and procedures, no matter
how well designed and operated, can provide only reasonable assurance of
achieving the desired control objectives, and management is required to apply
its judgment in evaluating the cost-benefit relationship of possible controls
and procedures.
The
Company carried out an evaluation under the supervision and with the
participation of its management, including its Chief Executive Officer and Chief
Financial Officer, of the effectiveness of its disclosure controls and
procedures as of the end of the period covered by this report. Based
on this evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that the Company’s disclosure controls and procedures were effective
as of December 31, 2009.
Management’s
Annual Report on Internal Control Over Financial Reporting
See
“Management’s Report on Internal Control Over Financial Reporting” in
Item 8. “Financial Statements and Supplementary Data.”
Changes
in the Company’s Internal Control Over Financial Reporting
The
Company’s management is also responsible for establishing and maintaining
adequate internal controls over financial reporting, as defined in
Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The
Company’s internal controls were designed to provide reasonable assurance as to
the reliability of its financial reporting and the preparation and presentation
of the consolidated financial statements for external purposes in accordance
with accounting principles generally accepted in the United States.
Because
of its inherent limitations, internal control over financial reporting may not
detect or prevent misstatements. Projections of any evaluation of the
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
There
were no changes in the Company’s internal controls over financial reporting
during the fourth quarter of 2009 that materially affected, or were reasonably
likely to materially affect, the Company’s internal control over financial
reporting.
None.
A list of
the Company’s executive officers and biographical information appears in
Part I in this Annual Report on Form 10-K under the caption “Executive
Officers of the Company.” Information about Company Directors may be
found under the caption “Election of Directors” of the Proxy Statement for the
Annual Meeting of Unitholders to be held on April 27, 2010 (the “2010 Proxy
Statement”). That information is incorporated herein by
reference.
The
information in the 2010 Proxy Statement set forth under the caption
“Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated
herein by reference.
The
information required by this item regarding audit committee related matters,
codes of ethics and committee charters is incorporated by reference from the
2010 Proxy Statement under the caption “Corporate Governance.”
Information
required by this item is incorporated herein by reference to the 2010 Proxy
Statement.
Information
required by this item is incorporated herein by reference to the 2010 Proxy
Statement.
Securities
Authorized for Issuance Under Equity Compensation Plans
The
following summarizes information regarding the number of units that are
available for issuance under all of the Company’s equity compensation plans as
of December 31, 2009:
|
Plan
Category
|
Number
of Securities to be
Issued
Upon Exercise of
Outstanding
Unit Options,
Warrants
and Rights
|
Weighted
Average Exercise
Price
of Outstanding Unit
Options,
Warrants
and
Rights
|
Number
of Securities
Remaining
Available for
Future
Issuance Under
Equity
Compensation
Plan
(Excluding
Securities
Reflected
in Column (a))
|
|||||||||||||
|
(a)
|
(b)
|
(c) | ||||||||||||||
|
Equity
compensation plans approved by security holders
|
1,947,843
|
$ |
22.51
|
6,822,795
|
||||||||||||
|
Equity
compensation plans not approved by security holders
|
—
|
—
|
—
|
|
||||||||||||
|
1,947,843
|
$ |
22.51
|
6,822,795 |
|
||||||||||||
Information
required by this item is incorporated herein by reference to the 2010 Proxy
Statement.
Information
required by this item is incorporated herein by reference to the 2010 Proxy
Statement.
(a) -
2. Financial Statement Schedules:
All
schedules are omitted for the reason that they are not required or the
information is otherwise supplied in Item 8. “Financial Statements and
Supplementary Data” in this Annual Report on Form 10-K.
(a) -
3. Exhibits Filed:
The
exhibits required to be filed by this Item 15 are set forth in the “Index
to Exhibits” accompanying this report.
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
LINN
ENERGY, LLC
|
|||
|
Date: February 25,
2010
|
By:
|
/s/
Mark E. Ellis
|
|
|
Mark
E. Ellis
|
|||
|
President
and Chief Executive Officer
|
|||
|
Date: February 25,
2010
|
By:
|
/s/
David B. Rottino
|
|
|
David
B. Rottino
|
|||
|
Senior
Vice President and
Chief
Accounting Officer
|
|||
Pursuant
to the requirements of the Securities Exchange Act of 1934, this Annual Report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||||||||
|
/s/
Michael C. Linn
|
Executive
Chairman
|
February
25, 2010
|
||||||||
|
Michael
C. Linn
|
||||||||||
|
/s/
Mark E. Ellis
|
President
and Chief Executive Officer
(Principal
Executive Officer)
|
February
25, 2010
|
||||||||
|
Mark
E. Ellis
|
||||||||||
|
/s/
Kolja Rockov
|
Executive
Vice President and
Chief
Financial Officer
(Principal
Financial Officer)
|
February 25,
2010
|
||||||||
|
Kolja
Rockov
|
||||||||||
|
/s/
David B. Rottino
|
Senior
Vice President and
Chief
Accounting Officer
(Principal
Accounting Officer)
|
February 25,
2010
|
||||||||
|
David
B. Rottino
|
||||||||||
|
/s/
George A. Alcorn
|
Independent
Director
|
February 25,
2010
|
||||||||
|
George
A. Alcorn
|
||||||||||
|
/s/
Terrence S. Jacobs
|
Independent
Director
|
February 25,
2010
|
||||||||
|
Terrence
S. Jacobs
|
||||||||||
|
/s/
Joseph P. McCoy
|
Independent
Director
|
February 25,
2010
|
||||||||
|
Joseph
P. McCoy
|
||||||||||
|
/s/ Jeffrey
C. Swoveland
|
Independent
Director
|
February 25,
2010
|
||||||||
|
Jeffrey
C. Swoveland
|
||||||||||
|
Exhibit
Number
|
Description
|
|||
|
2
|
.1†*
|
—
|
Asset
Purchase and Sale Agreement, dated November 25, 2009, between Linn
Energy Holdings, LLC and Merit Management Partners I, L.P., Merit
Management Partners II, L.P., Merit Management Partners III, L.P., Merit
Energy Partners III, L.P., Merit Energy Partners D-III, L.P., Merit Energy
Partners E-III, L.P. and Merit Energy Partners F-III,
L.P.
|
|
|
3
|
.1
|
—
|
Certificate
of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC)
(incorporated herein by reference to Exhibit 3.1 to Registration
Statement on Form S-1 (File No. 333-125501) filed by Linn
Energy, LLC on June 3, 2005)
|
|
|
3
|
.2
|
—
|
Certificate
of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now
Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to
Registration Statement on Form S-1 (File No. 333-125501) filed
by Linn Energy, LLC on June 3, 2005)
|
|
|
3
|
.3
|
—
|
Second
Amended and Restated Limited Liability Company Agreement of Linn Energy,
LLC dated January 19, 2006, (incorporated herein by reference to
Exhibit 3.3 to Annual Report on Form 10-K for the year ended
December 31, 2006, filed on March 30, 2007)
|
|
|
3
|
.4
|
—
|
Amendment
No. 1 to Second Amended and Restated Limited Liability Company
Agreement of Linn Energy, LLC dated October 24, 2006, (incorporated
herein by reference to Exhibit 3.4 to Annual Report on Form 10-K
for the year ended December 31, 2006, filed on March 30,
2007)
|
|
|
3
|
.5
|
—
|
Amendment
No. 2 to Second Amended and Restated Limited Liability Company
Agreement of Linn Energy, LLC dated February 1, 2007, (incorporated
herein by reference to Exhibit 3.5 to Annual Report on Form 10-K
for the year ended December 31, 2006, filed on March 30,
2007)
|
|
|
3
|
.6
|
—
|
Amendment
No. 3 to Second Amended and Restated Limited Liability Company
Agreement of Linn Energy, LLC dated August 31, 2007, (incorporated
herein by reference to Exhibit 4.1 to Current Report on
Form 8-K, filed on September 5, 2007)
|
|
|
4
|
.1
|
—
|
Form
of specimen unit certificate for the units of Linn Energy, LLC
(incorporated herein by reference to Exhibit 4.1 to Annual Report on
Form 10-K for the year ended December 31, 2005, filed on
May 31, 2006)
|
|
|
4
|
.2
|
—
|
Indenture,
dated as of June 27, 2008, among Linn Energy, LLC, Linn Energy
Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank
National Association, as Trustee (incorporated herein by reference to
Exhibit 4.1 to Current Report on Form 8-K filed on June 30,
2008)
|
|
|
4
|
.3
|
—
|
Indenture,
dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance
Corp., the Subsidiary Guarantors named therein and U. S. Bank National
Association, as trustee (incorporated herein by reference to
Exhibit 4.1 to Current Report on Form 8-K filed on May 18,
2009)
|
|
|
4
|
.4
|
—
|
Registration
Rights Agreement, dated May 18, 2009, among Linn Energy, LLC, Linn
Energy Finance Corp., the Subsidiary Guarantors named therein and the
representatives of the Initial Purchasers named therein (incorporated
herein by reference to Exhibit 4.2 to Current Report on Form 8-K
filed on May 18, 2009)
|
|
|
10
|
.1**
|
—
|
Linn
Energy, LLC Amended and Restated Long-Term Incentive Plan (incorporated
herein by reference to Annex A to the Proxy Statement for 2008 Annual
Meeting, filed on April 21, 2008)
|
|
|
10
|
.2**
|
—
|
Amendment
No. 1 to Linn Energy, LLC Amended and Restated Long-Term Incentive
Plan, dated February 4, 2009, (incorporated herein by reference to
Exhibit 10.2 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
|
10
|
.3**
|
—
|
Form
of Executive Unit Option Agreement pursuant to the Linn Energy, LLC
Amended and Restated Long-Term Incentive Plan, as amended (incorporated
herein by reference to Exhibit 10.3 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
|
10
|
.4**
|
—
|
Form
of Executive Restricted Unit Agreement pursuant to the Linn Energy, LLC
Amended and Restated Long-Term Incentive Plan, as amended (incorporated
herein by reference to Exhibit 10.4 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
|
Exhibit
Number
|
Description
|
||
|
10
|
.5**
|
—
|
Form
of Phantom Unit Grant Agreement for Independent Directors pursuant to the
Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended
(incorporated herein by reference to Exhibit 10.1 to Current Report
on Form 8-K filed on August 9, 2006)
|
|
10
|
.6**
|
—
|
Form
of Director Restricted Unit Grant Agreement pursuant to the Linn Energy,
LLC Amended and Restated Long-Term Incentive Plan, as amended
(incorporated herein by reference to Exhibit 10.6 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
10
|
.7**
|
—
|
Third
Amended and Restated Employment Agreement, dated effective as of
December 17, 2008, between Linn Operating, Inc. and Michael C.
Linn (incorporated herein by reference to Exhibit 10.7 to Annual
Report on Form 10-K for the year ended December 31, 2008, filed
on February 26, 2009)
|
|
10
|
.8**
|
—
|
Third
Amended and Restated Employment Agreement, dated effective as of
December 17, 2008, between Linn Operating, Inc. and Kolja Rockov
(incorporated herein by reference to Exhibit 10.8 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
10
|
.9**
|
—
|
Amended
and Restated Employment Agreement, dated effective as of December 17,
2008, between Linn Operating, Inc. and Mark E. Ellis (incorporated
herein by reference to Exhibit 10.9 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
10
|
.10**
|
—
|
Amended
and Restated Employment Agreement, dated effective December 17, 2008,
between Linn Operating, Inc. and Charlene A. Ripley (incorporated
herein by reference to Exhibit 10.10 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
10
|
.11**
|
—
|
Amended
and Restated Employment Agreement, dated effective December 17, 2008,
between Linn Operating, Inc. and Arden L. Walker, Jr. (incorporated
herein by reference to Exhibit 10.11 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
10
|
.12**
|
—
|
Second
Amended and Restated Employment Agreement, dated December 17, 2008,
between Linn Operating, Inc. and David B. Rottino (incorporated
herein by reference to Exhibit 10.12 to Annual Report on
Form 10-K for the year ended December 31, 2008, filed on
February 26, 2009)
|
|
10
|
.13**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
George A. Alcorn (incorporated herein by reference to
Exhibit 10.15 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.14**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Joseph P. McCoy (incorporated herein by reference to
Exhibit 10.16 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.15**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Terrence S. Jacobs (incorporated herein by reference to
Exhibit 10.17 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.16**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Jeffrey C. Swoveland (incorporated herein by reference to
Exhibit 10.18 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.17**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Michael C. Linn (incorporated herein by reference to
Exhibit 10.19 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.18**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Mark E. Ellis (incorporated herein by reference to Exhibit 10.20
to Annual Report on Form 10-K for the year ended December 31,
2008, filed on February 26, 2009)
|
|
10
|
.19**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Kolja Rockov (incorporated herein by reference to Exhibit 10.21 to
Annual Report on Form 10-K for the year ended December 31, 2008,
filed on February 26, 2009)
|
|
10
|
.20**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Charlene A. Ripley (incorporated herein by reference to
Exhibit 10.22 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
Exhibit
Number
|
Description
|
||
|
10
|
.21**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
David B. Rottino (incorporated herein by reference to
Exhibit 10.23 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.22**
|
—
|
Indemnity
Agreement, dated as of February 4, 2009, between Linn Energy, LLC and
Arden L. Walker, Jr. (incorporated herein by reference to
Exhibit 10.24 to Annual Report on Form 10-K for the year ended
December 31, 2008, filed on February 26,
2009)
|
|
10
|
.23**
|
—
|
Separation
Agreement, dated effective May 8, 2008, between Linn Operating, Inc.
and Thomas A. Lopus (incorporated herein by reference to
Exhibit 10.4 to Quarterly Report on Form 10-Q filed on
August 7, 2008)
|
|
10
|
.24
|
—
|
Fourth
Amended and Restated Credit Agreement dated as of April 28, 2009,
among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent,
and the Lenders and agents Party thereto (incorporated herein by reference
to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on
May 7, 2009)
|
|
10
|
.25
|
—
|
First
Amendment, dated May 15, 2009, to Fourth Amended and Restated Credit
Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as
Administrative Agent, and the Lenders and agents Party thereto
(incorporated herein by reference to Exhibit 10.1 to Quarterly Report
on Form 10-Q filed on August 6, 2009)
|
|
10
|
.26
|
—
|
Fourth
Amended and Restated Guaranty and Pledge Agreement, dated as of
April 28, 2009, made by Linn Energy, LLC and each of the other
Obligors in favor of BNP Paribas, as Administrative Agent (incorporated
herein by reference to Exhibit 10.2 to Quarterly Report on
Form 10-Q filed on May 7, 2009)
|
|
10
|
.27
|
—
|
Linn
Energy, LLC Change of Control Protection Plan, dated as of April 25,
2009, (incorporated herein by reference to Exhibit 10.3 to Quarterly
Report on Form 10-Q filed on May 7, 2009)
|
|
10
|
.28†**
|
—
|
Amendment
No. 1, dated effective as of January 1, 2010, to Third Amended
and Restated Employment Agreement, dated effective as of December 17,
2008, between Linn Operating, Inc. and Michael C.
Linn
|
|
10
|
.29†**
|
—
|
Amendment
No. 1, dated effective as of January 1, 2010, to Amended and
Restated Employment Agreement, dated effective as of December 17,
2008, between Linn Operating, Inc. and Mark E.
Ellis
|
|
21
|
.1†
|
—
|
Significant
Subsidiaries of Linn Energy, LLC
|
|
23
|
.1†
|
—
|
Consent
of KPMG LLP
|
|
23
|
.2†
|
—
|
Consent
of DeGolyer and MacNaughton
|
|
31
|
.1†
|
—
|
Section 302
Certification of Mark E. Ellis, President and Chief Executive Officer
of Linn Energy, LLC
|
|
31
|
.2†
|
—
|
Section 302
Certification of Kolja Rockov, Executive Vice President and Chief
Financial Officer of Linn Energy, LLC
|
|
32
|
.1†
|
—
|
Section 906
Certification of Mark E. Ellis, President and Chief Executive Officer
of Linn Energy, LLC
|
|
32
|
.2†
|
—
|
Section 906
Certification of Kolja Rockov, Executive Vice President and Chief
Financial Officer of Linn Energy, LLC
|
|
99
|
.1†
|
—
|
2009
Report of DeGolyer and MacNaughton
|
|
†
|
Filed
herewith.
|
|
*
|
The
schedules to this agreement have been omitted from this filing pursuant to
Item 601(b)(2) of Regulation S-K. The Company will furnish
copies of such schedules to the Securities and Exchange Commission upon
request.
|
|
**
|
Management
Contract or Compensatory Plan or Arrangement required to be filed as an
exhibit hereto pursuant to Item 601 of
Regulation S-K.
|
119