Filed Pursuant to Rule 424(b)(3)
File No. 333-125564
PROSPECTUS SUPPLEMENT NO. 1
(To Prospectus Dated March 22, 2006)
NATURAL GAS SYSTEMS, INC.
Common Stock
This document supplements our prospectus dated March 22, 2006 and
should be read in conjunction with the prospectus. This prospectus supplement
describes certain recent developments and contains information regarding recent
results of operations concerning Natural Gas Systems, Inc., and must be
delivered with the prospectus.
Transaction Involving our Delhi Field
As previously reported in a Current Report on Form 8-K that we filed
with the SEC on May 11, 2006, our wholly-owned subsidiary, NGS Sub Corp, entered
into a purchase and sale agreement with Denbury Onshore, LLC, a subsidiary of
Denbury Resources, Inc. (NYSE symbol: DNR) on May 8, 2006 to conduct an enhanced
oil recovery project utilizing CO2 flood technology in our Delhi Holt Bryant
Unit within the Delhi Field in northeast Louisiana (the "Delhi Unit"). On June
12, 2006, this transaction closed and we received approximately $50 million from
Denbury and delivered to Denbury an initial 100% working interest and 80% net
revenue interest in the Delhi Unit, and a 75% working interest and an 80% net
revenue interest (proportionately reduced to 60%) in certain other depths of the
Delhi Field. We retained a separate 4.8% royalty interest in the Delhi Field
(including the Delhi Unit) and a 25% working interest in certain other depths of
the Delhi Field (excluding the Delhi Unit, except as described below). Under the
terms of the agreement, Denbury has agreed to contribute all development
capital, technical expertise and required amounts of proven reserves of carbon
dioxide that will be injected into the Delhi Unit oil reservoirs. After the
project generates $200 million of net cash flows before capital expenditures for
Denbury, we will regain a 25% working interest (20% net revenue interest) in the
Delhi Unit.
As a result of this transaction, our liquidity has significantly
improved and our forward looking results from operations will likely change as
more fully described under "Significant Improvement in Liquidity" and "Forward
Looking Results Will Likely Change", respectively, in "Management's Discussion
and Analysis of Financial Condition and Results of Operations," below.
Copies of the Purchase and Sale Agreement and other definitive
agreements relating to this transaction have been filed with the SEC as exhibits
to our Current Report on Form 8-K filed with the SEC on June 15, 2006. For
information on obtaining our Form 8-K, including exhibits, see the discussion in
the prospectus under the caption "Where You Can Find More Information."
The date of this Prospectus Supplement is June 28, 2006
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Management's Discussion and Analysis of Financial Condition and Results of
Operations
The following information updates the discussion under the heading
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the prospectus and should be read in conjunction with that
discussion.
Liquidity and Capital Resources
Significant Improvement in Liquidity
As a result of our recent transaction with Denbury Resources, Inc.
(NYSE symbol: DNR) described above, our liquidity has improved significantly.
Under the terms of this transaction, on June 12, 2006 we received approximately
$50 million in cash, and a 25% after payout back-in working interest in the
enhanced oil recovery project Denbury has undertaken to fund and operate.
Of the approximately $50 million in proceeds, we immediately used
approximately $5.4 million to repay in full our credit facility and used
approximately $257,000 to repay a subordinated loan to our Chairman (see
"Repayment of Loans" below). Consequently, we currently have no indebtedness,
other than ordinary course trade payables, and we have sufficient cash resources
to continue with the implementation of our business strategy for the foreseeable
future. We plan to deposit a minimum of $3 million, and a maximum of up to $16
million of the proceeds, with the U. S. Treasury and the Louisiana Department of
Revenue for income taxes due on the gain on sale of our Delhi property,
depending on the amount of IRC 1031 like-kind property exchanges we ultimately
consummate. The estimated remaining balance of these proceeds (being a range of
approximately $28.3 million to $41.3 million, depending on our ultimate taxable
gain) will be used to identify and close additional oil and gas investment
opportunities that fit our business plan, and for working capital and general
corporate purposes.
We have not determined the exact amounts we plan to expend on the above
uses or the timing of such expenditures. The amounts actually expended and the
timing are at our discretion and may vary significantly depending upon a number
of factors, including our ability to identify and close additional oil and gas
opportunities that fit our business plan within the 45 and 180 day windows
allotted to identify and consummate any IRC 1031 like-kind exchanges. Pending
their use as set forth above, such proceeds will be invested in a U.S.
Government money market account.
Repayment of Loans
As previously reported in a Current Report on Form 8-K filed by us on
February 2, 2005 with the SEC, we entered into a senior secured loan agreement
(the "Loan Agreement") with Prospect Energy Corporation ("Prospect") providing
for borrowings by us of up to $4.8 million. The borrowings were secured by
substantially all of our assets. The outstanding indebtedness bore interest at
an annual rate equal to the greater of (a) 14% and (b) the Treasury Rate plus
9%, with interest payable in arrears on the last day of each month. All
outstanding indebtedness was to become due in full on February 2, 2010. Pursuant
to a number of amendments to the Loan Agreement, the total face amount of
borrowings at maturity drawn by us was $5.0 million.
On May 31, 2006, we voluntarily prepaid all amounts due under the Loan
Agreement totaling $5,437,352, representing the then-outstanding principal
balance of $5,000,000, all accrued and unpaid interest, a prepayment penalty and
certain other amounts due and owing under the Loan Agreement. We also issued
Prospect an additional five-year warrant to purchase up to 100,000 shares of our
common stock at an exercise price of $2.71 per share in satisfaction of a
disputed obligation relating to a voluntary waiver by Prospect of a technical
breach of a negative covenant by us. Concurrent with this repayment the Loan
Agreement was terminated and all of the collateral attached thereto was
released.
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On March 3, 2006, we borrowed $250,000 from Laird Q. Cagan, the
chairman of our board, for working capital. This loan had a one-year term and
accrued interest at the annual rate of 10%, payable at maturity. The loan also
had certain acceleration provisions in the event we were to raise additional
capital in excess of $2 million. On June 13, 2006, we voluntarily prepaid all
amounts due under this loan totaling $257,058, representing the then-outstanding
principal balance and all accrued and unpaid interest.
Mr. Cagan acts as our non-exclusive placement agent for capital raising
services through Chadbourn Securities, Inc., and his company, Cagan McAfee
Capital Partners, provides financial advisory services to us under the terms of
a written agreement previously filed with the SEC.
Cash Flow for the nine months ended March 31, 2006
Cash used in operating activities for the nine months ended March 31,
2006 was $632,967 and cash used in operations for the comparative period was
$739,684. The decrease in cash used in operating activities was primarily due to
lower net cash losses from operations before changes in working capital, offset
with higher operating expenses resulting in higher operating losses.
Cash used in investing activities in the nine months ended March 31,
2006 and 2005 was $2,891,009 and $2,186,724, respectively. In 2006, the majority
of the development capital expenditures were spent on the 2005 Delhi Development
Drilling Program and for the purchase of an additional net revenue interest in
one of our existing field. For the nine months ended March 31, 2005, we expended
approximately $1,836,878, in capital expenditures, of which approximately
$725,000 was for the acquisition of producing properties in Tullos Field Area.
Cash provided by financing activities for the nine months ended March
31, 2006 was $1,183,119. This was primarily from loan proceeds of $1,250,000,
offset by $6,754 used to pay off the remaining note for property insurance;
$22,654 for deferred financing fees related to the additional $1.0 million
drawdown from Prospect, and $37,473 for miscellaneous transaction costs related
to equity raising activities. Comparatively, $3,536,987 was provided in the
comparable period which consisted of $3,855,721 in net proceeds from loans,
$1,737,336 payments on notes, $1,678,307 of gross cash proceeds from the private
sale of our common stock and $259,705 of deferred financing fees.
Budgeted Capital Expenditures. Our 2005 Delhi Development Drilling Program began
in early October, 2005 and completion activities ended in March 2006. As of
March 31, 2006 we had drilled and completed five wells at an estimated total
cost to date of $1.7 million. The two option wells we originally planned for the
2005 program (wells six and seven) were postponed due to heavy rains at Delhi
during January 2006.
Results of Operations
Forward-Looking Results Will Likely Change
Due to our purchase and sale agreement with Denbury Onshore LLC,
described under "Transaction Involving our Delhi Field" above, further
initiatives concerning our Delhi Development Drilling Program are expected to be
replaced with the much larger enhanced oil recovery (EOR) project utilizing CO2
flood technology, which Denbury has undertaken to fund and operate. The Denbury
agreement, although exceeding our original expectations for development results
at Delhi, will result in the immediate loss of production and revenues from
Delhi (excluding our override on existing production) until such time as the EOR
project is completed and brought online by Denbury. Without further acquisitions
of new properties, or production increases at our Tullos Field Area, our
production and revenues will decline in the foreseeable future, as compared to
our March 31, 2006 results.
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Summary for three and nine month periods ended March 31, 2006
We have continued our growth in critical metrics of production and
revenues while limiting our cash overhead costs. In the most recent three months
ended March 31, 2006, our sales volumes and revenues increased by 74% and 132%,
respectively, over the prior year three month period. For the nine months ended
March 31, 2006, our sales volumes and revenues increased by 85% and 131%,
respectively, over the prior year nine month period. After accounting for lease
operating expense and production taxes, field income before depletion expense
increased 134% and 115% for the three and nine months ended March 31, 2006,
respectively, while general and administrative expenses declined 31% and rose
8%, respectively for the same periods. Losses from Operations declined 49% and
9% for the comparable three and nine month periods.
The drilling results of our 2005 Delhi Development Drilling Program did
not produce the immediate favorable results we expected. From a technical
perspective, we generally found the targeted reservoirs "up-dip" of previously
watered-out zones at the structural level and thickness predicted. It appears
that the reservoirs we targeted became less permeable toward the truncation
point, or updip limit, thereby resulting in far less production than
anticipated. We believe that artificial stimulation of the reservoirs, or
hydraulic fracturing, may result in improved production rates. Such stimulations
would require further expenditures and contain an element of risk as to success.
Furthermore, the problems encountered in drilling and completing the wells due
to the changed reservoir quality and quality of the vendor services we received
led to far higher capital expenditures than budgeted.
Three months ended March 31, 2006 compared to three months ended March 31, 2005.
The following table sets forth certain financial information with
respect to our oil and gas operations.
Three Months Ended
March 31,
------------------------
Net to NGS 2006 2005 Variance % change
----------- ----------- ------------ -----------
Sales Volumes:
Oil (Bbl) 14,496 6,545 7,951 121%
Gas (Mcf) 10,003 16,378 (6,375) -39%
Oil and Gas (Boe) 16,163 9,275 6,888 74%
Revenue data (a):
Oil Revenue $ 794,872 $ 267,225 $ 527,647 197%
Gas Revenue 83,730 111,722 (27,992) -25%
----------- ----------- ------------
Total oil and gas revenues $ 878,602 $ 378,947 $ 499,655 132%
Average prices (a):
Oil (per Bbl) $ 54.83 $ 40.83 $ 14.00 34%
Gas (per Mcf) 8.37 6.82 1.55 23%
Oil and Gas (per Boe) 54.36 40.86 13.50 33%
Expenses (per BOE)
Lease operating expenses and production taxes $ 33.84 $ 25.93 $ 7.91 31%
Depletion expense on oil and gas properties 8.12 6.01 2.11 35%
(a) Includes the cash settlement of hedging contracts
Net Loss. For the three months ended March 31, 2006, we reported a net
loss of $608,132 or $0.02 loss per share on total revenues of $878,602, as
compared to a net loss of $906,936 or $0.04 loss per share on total revenues of
$378,947 for the three months ended March 31, 2005. The decrease in loss is
attributable primarily to higher revenues due to increased production and sales
volumes, higher commodity prices, lower general and administrative expenses,
offset by unfavorable nonrecurring lease operating costs.
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Sales Volumes. Oil sales volumes, net to our interest, for the three
months ended March 31, 2006 increased 121% to 14,496 Bbls, compared to 6,545
Bbls for the three months ended March 31, 2005. The increase in sales volumes is
primarily due to oil sales from the Chadco acquisition in the Tullos Field Area
and the result of workovers, recompletions and the development drilling program
at Delhi field.
Net natural gas volumes sold for the three months ended March 31, 2006
were 10,003 Mcfs, a decrease of 39% from the three months ended March 31, 2005.
The normal decline rate is primarily attributable for this decrease, slightly
offset by the new Delhi 92-2 well which was drilled and completed in early
November.
Production. Oil production varies from oil sales volumes by changes in
crude oil inventories, which are not carried on the balance sheet. Net oil
production for the three months ended March 31, 2006 increased 97% to 13,890
Bbls, compared to 7,046 Bbls for the three months ended March 31, 2005. This is
primarily due to the acquisition of additional wells in the Tullos Field Area
and results of development drilling and other work in the Delhi Field. Net
natural gas production for the three months ended March 31, 2006 decreased 54%
to 10,147 Mcfs, compared to 21,846 Mcfs for the three months ended March 31,
2005, due to depletion in all gas wells at Delhi field.
Oil and Gas Revenues. Revenues presented in the table above and
discussed herein represent revenue from sales of our oil and natural gas
production volumes, net to our interest. Production sold under fixed price
delivery contracts, which have been designated for the normal purchase and sale
exemption under SFAS 133, are also included in these amounts. Realized prices
may differ from market prices in effect during the periods, depending on when
the fixed delivery contract was executed.
Oil and gas revenues increased 132% for the three month period ended
March 31, 2006, compared to the same period in 2005, as a result of increases in
sales volumes due primarily to the Chadco acquisition of producing leases in the
Tullos Field Area and the Delhi Development drilling program. Another component
of the revenue increase is a 33% increase in the sales prices received per BOE
during the three months ended March 31, 2006 as compared to the three months
ended March 31, 2005.
Lease Operating Expenses. Lease operating expenses for the three months
ended March 31, 2006 increased $306,551 from the comparable 2005 period to
$547,029. The increase in operating expenses in 2006 is primarily attributable
to (1) an increase in the number of active wells due to the acquisition of
producing properties in the Tullos Field Area; (2) substantial increases in
overall industry service costs and (3) nonrecurring lease cleanup costs.
General and Administrative Expenses. General and administrative
expenses were $593,271for the three months ended March 31, 2006, a decrease of
$262,669 from $855,940 for the three months ended March 31, 2005. Non-cash stock
compensation expense decreased approximately $400,000 from the prior comparative
quarter, offset by higher overall general and administrative expenses in the
current quarter due to significant expenses associated with a being a public
registrant, including expenses for audited financial statements, SEC counsel,
outside engineering estimates, D&O insurance, outside director fees and other
related costs.
Depletion and Amortization Expense. Depletion and amortization expense
increased $75,516 for the three months ended March 31, 2006 to $131,246 from
$55,730 for the same period in 2005. The increase is primarily due to a 74%
increase in sales volumes and a 35% increase in the average depletion rate,
period over period.
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Interest Expense. Interest expense for the three months ended March 31,
2006 increased $86,364 to $221,694 (of which $160,713 was cash expense) compared
to $135,330 (of which $70,762 was cash expense) for the three months ended March
31, 2005. The increase in interest expense was primarily due to interest expense
associated with the Prospect facility, which was only partially outstanding in
the comparable period.
Nine months ended March 31, 2006 compared to nine months ended March 31, 2005
Nine Months Ended
March 31,
------------------------------
Net to NGS 2006 2005 Variance % change
-------------- -------------- -------------- --------------
Sales Volumes:
Oil (Bbl) 35,277 15,747 19,530 124%
Gas (Mcf) 43,962 43,495 467 1%
Oil and Gas (Boe) 42,604 22,996 19,608 85%
Revenue data (a):
Oil Revenue $ 1,831,804 682,679 $ 1,149,125 168%
Gas Revenue 420,618 293,203 127,415 43%
-------------- -------------- --------------
Total oil and gas revenues $ 2,252,422 $ 975,882 $ 1,276,540 131%
Average prices (a):
Oil (per Bbl) $ 51.93 $ 43.35 $ 8.58 20%
Gas (per Mcf) 9.57 6.74 2.83 42%
Oil and Gas (per Boe) 52.87 42.44 10.43 25%
Expenses (per BOE)
Lease operating expenses and production taxes $ 33.94 $ 26.10 $ 7.84 30%
Depletion expense on oil and gas properties 7.52 6.82 0.70 10%
(a) Includes the cash settlement of hedging contracts
Net Loss. For the nine months ended March 31, 2006, we reported a net
loss of $1,950,074 or $0.08 loss per share on total revenues of $2,252,422, as
compared with a net loss of $1,682,775 or $0.07 loss per share on total revenues
of $975,882 for the nine months ended March 31, 2005. The increase in loss is
attributable to overall increases in lease operating and general and
administrative expenses including nonrecurring lease operating costs, partially
offset by increases in revenues due to higher sales volumes and sales prices.
Excluding non-cash stock compensation expense of $381,385, our net loss for the
nine months ended March 31, 2006 was $1,568,689, or $0.06 loss per share. By
comparison, excluding non-cash stock compensation expense of $620,588 for the
nine months ended March 31, 2005, our net loss was $1,062,187, or $0.05 loss per
share.
Sales Volumes. Oil sales volumes, net to our interest, for the nine
months ended March 31, 2006 increased 124% to 35,277 Bbls, compared to 15,747
Bbls for the nine months ended March 31, 2005. The increase in sales volumes is
primarily due to oil sales from the Chadco acquisition in the Tullos Field Area,
the result of workovers and recompletions in our portfolio and the results of
the development drilling program at Delhi field.
Net natural gas volumes sold for the nine months ended March 31, 2006
were 43,962 Mcfs, an increase of 1% from the nine months ended March 31, 2005.
Normal production declines were offset with new sales volumes from the Delhi
92-2 well which was drilled and completed in late 2005.
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Production. Oil production varies from oil sales volumes by changes in
crude oil inventories, which are not carried on the balance sheet. Net oil
production for the nine months ended March 31, 2006 increased 122% to 36,390
Bbls, compared to 16,421Bbls for the nine months ended March 31, 2005. This is
primarily due to the acquisition of wells in the Tullos Field Area, the result
of workovers and recompletions in our portfolio and the results of the
development drilling program at Delhi field.
Our net oil stock ending inventory decreased approximately 28% at March
31, 2006 to approximately 4,300 Bbls, as compared to approximately 6,000 Bbls at
March 31, 2005. Decreases in oil inventory were attributable to coordinating
with our purchaser to pick up half loads at Tullos Field area since many of
these leases do not make a full truckload within one month (one truckload equals
~ 160 Bbls). This has caused erratic oil runs from month to month.
Net natural gas production for the nine months ended March 31, 2006
decreased 10% to 53,716 Mcfs, compared to 59,367 Mcfs for the nine months ended
March 31, 2005. Normal production declines were offset with new production from
the Delhi 92-2 well which was drilled and completed in late 2005.
Oil and Gas Revenues. Revenues presented in the table above and
discussed herein represent revenue from sales of our oil and natural gas
production volumes, net to our interest. Production sold under fixed price
delivery contracts, which have been designated for the normal purchase and sale
exemption under SFAS 133, are also included in these amounts. Realized prices
may differ from market prices in effect during the periods, depending on when
the fixed delivery contract was executed.
Oil and gas revenues increased 131% for the nine month period ended
March 31, 2006, compared to the same period in 2005, as a result of a 85%
increase in production volumes due to the Chadco and Atkins acquisitions of
producing leases in the Tullos Field Area and increases in production from our
Delhi Field as a result of the development drilling program. Another component
of the increase was a 25% increase in the average sales prices we received per
BOE during the nine months ended March 31, 2006 as compared to the nine months
ended March 31, 2005.
Lease Operating Expenses. Lease operating expenses for the nine months
ended March 31, 2006 increased $845,732 from the comparable 2005 period to
$1,445,923. The increase in operating expenses for this nine period is primarily
attributable to (1) an increase in the number of active wells due to the
acquisition of properties in the Tullos Field Area, (2) substantial increases in
overall industry service costs, (3) high workover costs associated with our
Delhi 87-2 and 197-2 wells, repairs to our salt water disposal system and
repairs to two separate gas gathering line leaks, and (4) nonrecurring lease
cleanup costs.
On a BOE basis, lease operating expense and production taxes totaling
$33.94 per BOE did not meet our expectations for the nine months ended March 31,
2006, as compared to the prior year's comparable period of $26.10. The
unfavorable variance in the current period was predominately due to the
previously mentioned workover costs associated with an unusually large number of
our Delhi wells, combined with the loss of production from well downtime while
working over the wells. Over half of this unfavorable variance was attributable
to workover expenses incurred to maintain production on our Delhi 87-2 well,
which currently accounts for the majority of our production from our Delhi
Field. As previously reported, our Delhi 87-2 well is over 50 years old.
General and Administrative Expenses. General and administrative
expenses for the nine months ended March 31, 2006 were $1,839,655, an increase
of $132,784 as compared to $1,706,871 for the comparable prior year period. The
increase is primarily due to an increase in employees from two to five and
implementation of an outsourced property accounting service with Petroleum
Financial Incorporated. Overall general and administrative expenses are high due
to expenses associated with a being a public registrant, including expenses for
audited financial statements, SEC counsel, outside engineering estimates,
director & officer insurance, outside director fees and other related costs;
offset by a decrease in non-cash stock compensation expense of approximately
$239,000, from the comparative period.
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Depletion and Amortization Expense. Depletion and amortization expense
increased $163,773 for the nine months ended March 31, 2006 to $320,594 from
$156,821 for the same period in 2005. The increase is primarily due to an 85%
increase in sales volumes and a 10% increase in the average depletion rate,
period over period.
Interest Expense. Interest expense for the nine months ended March 31,
2006 increased $432,690 to $634,388 (of which $443,229 was cash expense)
compared to $201,698 (of which $168,475 was cash expense) for the nine months
ended March 31, 2005. The increase in interest expense was primarily due to
interest expense associated with the Prospect facility, which was only partially
outstanding in the comparable period.
Approval to List our Shares on the American Stock Exchange
On June 20, 2006, we received approval from the American Stock Exchange
to accept our shares for trading. However, AMEX approval is contingent upon our
being in compliance with all applicable listing standards on the date we begin
trading on the Exchange, and may be rescinded if we are not in compliance with
such standards.
Although we can give no assurances, we are actively attempting to
complete this process, with the expectation that our shares may begin trading by
early July, 2006.
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