UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-QSB
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934.
For the quarterly period ended December 31, 2005
or
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period ____________ to _____________
COMMISSION FILE NUMBER 000-27862
NATURAL GAS SYSTEMS, INC.
(Exact name of registrant as specified in charter)
NEVADA 41-1781991
------ ----------
(State or other jurisdiction (I.R.S. employer identification no.)
of incorporation or organization)
820 Gessner, Suite 1340, Houston, Texas 77024
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code: (713) 935-0122
Check whether the registrant (1) 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:|_|
Check whether the registrant is an accelerated filer (as defined in Rule 12b-2
of the Exchange Act.). Yes: |_| No: |X|
The number of shares outstanding of Registrant's common stock, par value $0.001,
as of February 1, 2006, was 24,948,364.
Transitional Small Business Disclosure Format (Check one): Yes: |_| No: |X|
NATURAL GAS SYSTEMS, INC.
TABLE OF CONTENTS
Page
PART I. FINANCIAL INFORMATION Number
------------------------------ ------
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets: December 31, 2005 (unaudited) and
June 30, 2005 3
Consolidated Statements of Operations (unaudited): For the three
and six months ended December 31, 2005 and 2004 4
Consolidated Statements of Cash Flows (unaudited): For the six
months ended December 31, 2005 and 2004 5
Notes to Consolidated Financial Statements (unaudited) 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 11
ITEM 3.CONTROLS AND PROCEDURES 16
PART II. OTHER INFORMATION
---------------------------
ITEM 1. LITIGATION 17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 17
ITEM 6. EXHIBITS 17
SIGNATURES 18
PART I - FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
December 31, June 30,
2005 2005
------------ ------------
(Unaudited)
Assets
Current Assets:
Cash $ 433,465 $ 2,548,688
Accounts receivable, trade 316,162 300,761
Inventories (materials & supplies) 455,247 222,470
Prepaid expenses 132,788 84,304
Retainers and deposits 66,335 56,335
------------ ------------
Total current assets 1,403,997 3,212,558
Oil & Gas properties - full cost 6,589,365 5,276,303
Oil & Gas properties - not amortized 44,844 61,887
Less: accumulated depletion (502,739) (313,391)
------------ ------------
Net oil & gas properties 6,131,470 5,024,799
Furniture, fixtures, and equipment, at
cost 14,684 12,113
Less: accumulated depreciation (5,734) (3,401)
------------ ------------
Net furniture, fixtures, and
equipment 8,950 8,712
Restricted deposits 868,263 863,089
Other assets 318,080 356,066
------------ ------------
Total assets $ 8,730,760 $ 9,465,224
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 400,161 $ 240,389
Accrued liabilities 261,225 276,470
Notes payable, current 0 6,754
Royalties payable 123,586 89,713
------------ ------------
Total current liabilities 784,972 613,326
Long term Liabilities:
Notes payable 4,000,000 4,000,000
Discount on notes payable (1,023,776) (1,093,452)
Asset retirement obligations 447,315 433,250
------------ ------------
Total liabilities 4,208,511 3,953,124
Stockholders' Equity:
Common Stock, par value $0.001
per share; 100,000,000 shares
authorized, 24,788,364
and 24,774,606 shares issued and
outstanding as of December 31, 2005
and June 30, 2005, respectively 24,788 24,774
Additional paid-in-capital 9,706,584 9,611,767
Deferred stock based compensation (338,023) (595,283)
Accumulated deficit (4,871,100) (3,529,158)
------------ ------------
Total stockholders' equity 4,522,249 5,512,100
------------ ------------
Total liabilities and stockholders'
equity $ 8,730,760 $ 9,465,224
============ ============
See accompanying notes to condensed consolidated financial statements.
2
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
Three Months Ended Six Months Ended
December 31, December 31,
2005 2004 2005 2004
--------------------------- ---------------------------
Revenues:
Oil sales $ 557,439 $ 250,931 $ 1,043,834 $ 415,454
Gas sales 278,955 114,837 336,888 181,481
Price risk management
activities (5,458) 0 (6,902) 0
--------------------------- ---------------------------
Total revenues 830,936 365,768 1,373,820 596,935
Expenses:
Lease operating costs 398,686 193,469 862,876 331,217
Production taxes 21,536 12,470 36,020 28,494
Depreciation, depletion and
amortization 114,431 53,986 191,681 101,092
General and administrative 662,106 540,569 1,246,384 851,704
--------------------------- ---------------------------
Total operating expenses 1,196,759 800,494 2,336,961 1,312,507
--------------------------- ---------------------------
Loss from operations (365,823) (434,726) (963,141) (715,572)
Other revenues and expenses:
Interest income 14,955 2,621 33,892 6,097
Interest expense (191,016) (41,102) (412,694) (66,368)
--------------------------- ---------------------------
Total other revenues and
expenses (176,061) (38,481) (378,802) (60,271)
--------------------------- ---------------------------
Net loss $ (541,884) $ (473,207) $ (1,341,943) $ (775,843)
=========================== ===========================
Loss per common share, basic and
diluted $ (0.02) $ (0.02) $ (0.05) $ (0.03)
Weighted average number of common
shares, basic and diluted 24,780,405 23,357,807 24,778,730 23,334,443
See accompanying notes to condensed consolidated financial statements.
3
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
Six months Six months
Ended Ended
December 31, December 31,
2005 2004
-----------------------------
Cash flow from operating activities:
Net loss $ (1,341,943) $ (775,843)
Adjustments to reconcile net loss to net
cash used by operating activities:
Stock-based compensation 269,351 111,120
Depletion 189,348 101,092
Depreciation 2,333 772
Accretion of asset retirement
obligation 14,065 6,581
Accretion of debt discount and non-cash
interest 130,178 0
Other non-cash items 50,232 0
Changes in assets and liabilities:
Accounts receivable (15,401) (64,741)
Inventories (232,777) (47,855)
Accounts payable 159,772 484,690
Royalties payable 33,873 0
Prepaid expenses (48,484) (12,772)
Accrued liabilities (15,245) 128,501
------------ ------------
Net cash used by operating
activities (804,698) (68,455)
Cash flow from investing activities:
Capital expenditures for oil and gas
properties (1,296,019) (885,660)
Capital expenditures for furniture,
fixtures and equipment (2,571) 0
Restricted deposits and retainers (15,174) 0
Other assets 9,993 (53,255)
------------ ------------
Net cash used in investing
activities (1,303,771) (938,915)
Cash flow from financing activities:
Proceeds from notes payable 0 977,875
Payments on notes payable (6,754) (775,972)
Proceeds from issuance of common stock 0 529,199
------------ ------------
Net cash provided by (used in)
financing activities (6,754) 731,102
------------ ------------
Net decrease in cash (2,115,223) (276,268)
Cash and cash equivalents, beginning of
period 2,548,688 367,831
------------ ------------
Cash and cash equivalents, end of period $ 433,465 $ 91,563
============ ============
Supplemental disclosure of cash flow
information:
Interest paid $ 282,516 $ 18,452
See accompanying notes to condensed consolidated financial statements.
4
NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization and Basis of Preparation
Headquartered in Houston, Texas, Natural Gas Systems, Inc. (the "Company",
"NGS", "we" or "us") is a petroleum company incorporated under the laws of the
State of Nevada, engaged primarily in the acquisition, exploitation and
development of properties for the production of crude oil and natural gas from
underground reservoirs. We acquire established oil and gas properties and
exploit them through the application of conventional and specialized technology
to increase production, ultimate recoveries, or both. At December 31, 2005, we
conducted operations through the 100% working interests we own in our Delhi
Field and Tullos Field Area, all located in Louisiana.
The accompanying unaudited condensed consolidated financial statements have been
prepared in accordance with accounting principles generally accepted in the
United States of America ("GAAP") for interim financial information and, with
the instructions to Form 10-QSB and Item 310(b) of Regulation S-B. All
adjustments (consisting of normal recurring accruals) which are, in the opinion
of management, necessary for a fair presentation of the results of operations
for the interim periods have been included. All inter-company transactions are
eliminated upon consolidation. The interim financial information and notes
hereto should be read in conjunction with our 2005 Annual Report on Form 10-KSB
and Form 10-KSB/A for the year ended June 30, 2005, as filed with the Securities
and Exchange Commission. The results of operations for the three and six months
ended December 31, 2005 are not necessarily indicative of results to be expected
for the entire fiscal year.
2. Recent Accounting Pronouncements
In December 2004, the FASB issued Statement of Financial Accounting Standards
No. 123R "Shared Based Payment" ("SFAS 123R"). This statement is a revision of
SFAS Statement No. 123 "Accounting for Stock-Based Compensation" and supersedes
APB Opinion No. 25, "Accounting for Stock Issued to Employees," and its related
implementation guidance. SFAS 123R addresses all forms of shared based
compensation ("SBP") awards, including shares issued under employee stock
purchase plans, stock options, restricted stock and stock appreciation rights.
Under SFAS 123R, SBP awards result in a cost that will be measured at fair value
on the awards' grant date, based on the estimated number of awards that are
expected to vest and will be reflected as compensation cost in the historical
financial statements. This statement is effective for public entities that file
as small business issuers as of the beginning of the first interim or annual
reporting period of the registrant's first fiscal year beginning after December
15, 2005. We are in the process of evaluating whether SFAS No. 123R will have a
significant impact on our overall results of operations or financial position.
3. Asset Retirement Obligations
SFAS No. 143, "Accounting for Asset Retirement Obligations," ("SFAS 143")
provides accounting requirements for retirement obligations associated with
tangible long-lived assets, including: 1) the timing of liability recognition;
2) initial measurement of the liability; 3) allocation of asset retirement cost
to expense; 4) subsequent measurement of the liability; and 5) financial
statement disclosures. SFAS 143 requires that an asset retirement cost should be
capitalized as part of the cost of the related long-lived asset and subsequently
allocated to expense using a systematic and rational method.
The reconciliation of the beginning and ending asset retirement obligation for
the period ending December 31, 2005 is as follows:
Asset retirement obligation at June 30, 2005 $ 433,250
Liabilities incurred --
Liabilities settled --
Accretion expense 14,065
-------------
Asset retirement obligation at December 31, 2005 $ 447,315
4. Loss per Share
Basic earnings per share is computed by dividing net income (loss) available to
common shareholders by the weighted average number of common shares outstanding
during the period. Diluted earnings per share are determined on the assumption
that outstanding stock options have been converted using the average price for
the period. For purposes of computing earnings per share in a loss year,
potential common shares have been excluded from the computation of weighted
average common shares outstanding, because their effect is anti-dilutive.
5
The following table sets forth the computation of basic and diluted earnings
(loss) per share:
Three months ended
December 31
------------------------------
2005 2004
-------------- -------------
Numerator:
Net loss applicable to common
stockholders $ (541,884) $ (473,207)
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible
subordinated notes N/A N/A
------------ ------------
Net loss applicable to common
stockholders plus assumed conversions $ (541,884) $ (473,207)
============ ============
Denominator: 24,780,405 23,357,807
Affect of potentially dilutive common shares:
Warrants N/A N/A
Employee and director stock options N/A N/A
Convertible preferred stock N/A N/A
Convertible subordinated notes N/A N/A
Redeemable preferred stock N/A N/A
------------ ------------
Denominator for dilutive earnings per 24,780,405 23,357,807
share - weighted average shares
============ ============
Loss per common share:
Basic and diluted $ (0.02) $ (0.02)
============ ============
Six months ended
December 31
------------------------------
2005 2004
-------------- -------------
Numerator:
Net loss applicable to common
stockholders $ (1,341,943) $ (775,843)
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible
subordinated notes N/A N/A
------------ ------------
Net loss applicable to common
stockholders plus assumed conversions $ (1,341,943) $ (775,843)
============ ============
Denominator: 24,778,730 23,334,443
Affect of potentially dilutive common shares:
Warrants N/A N/A
Employee and director stock options N/A N/A
Convertible preferred stock N/A N/A
Convertible subordinated notes N/A N/A
Redeemable preferred stock N/A N/A
------------ ------------
Denominator for dilutive earnings per
share - weighted average shares 24,778,730 23,334,443
============ ============
Loss per common share:
Basic and diluted $ (0.05) $ (0.03)
============ ============
5. Long-term Debt
On February 3, 2005 we closed a financing agreement with Prospect Energy
Corporation (the "Prospect Facility" or "Facility") and ultimately borrowed
$4,000,000, secured by all of our assets. At December 31, 2005, our book balance
was $2,976,224, net of the discount through such date. At maturity, or exclusive
of any prepayment penalty on early prepayment, the total amount owed under the
Facility will be $4,000,000.
6
Among other restrictions and subject to certain exceptions, the Facility
restricts us from creating liens, entering into certain types of mergers or
consolidations, incurring additional indebtedness, changing the character of our
business, or engaging in certain types of transactions. The Facility also
requires us to maintain specified financial ratios, including a 1.5:1 ratio of
borrowing base to debt and, a 2.0:1 ratio of operating cash flow to interest
expense (exclusive of accretion expense).
Effective September 22, 2005, we entered into an amendment to the Facility,
thereby obtaining covenant relief with respect to our obligation to maintain an
Earnings Before Interest (cash basis), Taxes, Depreciation and Amortization
("EBITDA") to interest payable coverage ratio of 2.0:1. The amendment changes
our compliance date to begin not later than the three months ended January 31,
2006, as compared to October 31, 2005 under the original terms of the agreement.
This amendment was effected in order to allow us to proceed with the delayed
drilling program of proved undeveloped reserve locations in our Delhi Field, the
results of which we are relying on to achieve the EBITDA coverage ratio required
of us by the Prospect Facility. In consideration for the amendment, we issued to
Prospect Energy Corporation (Prospect) revocable warrants to purchase 200,000
shares of our common stock, exercisable at $1.36 per share over five years. As a
result, $32,509, representing the fair value of the warrants, as determined
using the Black-Scholes option pricing model, was charged to interest expense
during the three months ended September 30, 2005. The warrants will be
automatically revoked in the event we achieve $200,000 in EBITDA, as defined,
for any one month period through April 30, 2006. We also agreed to limit our
acquisitions of additional oil and gas properties to a maximum of $100,000 (plus
the amount of proceeds to us from financing transactions and positive cash flow
from operations, if any, in each case subsequent to September 22, 2005) until we
achieve a trailing three month EBITDA to interest coverage ratio of 2.0:1. The
limitation does not include any evaluation costs, so that we may continue to
review new projects.
6. Stock-Based Compensation
SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148,
"Accounting for Stock-Based Compensation--Transition and Disclosure,"
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. We account for
stock-based compensation using the intrinsic value method prescribed in
Accounting Principles Board Opinion 25, "Accounting for Stock Issued to
Employees" ("APB 25").
Options
In December 2005, we: (i) granted a non-qualified stock option to
purchase 100,000 shares of common stock with an exercise price equal to the
market price of the underlying common stock on the date of grant, with a ten
year term and two year vesting schedule, to William E. Dozier, a newly elected
independent member of our board of directors, (ii) made a direct stock grant of
10,000 shares of common stock (outside of the 2004 Stock Plan) to an outside
consultant for services previously performed, resulting in $12,091 of stock
compensation expense being recorded, (iii) accelerated the vesting of options
granted to Messrs. Stoever and DiPaolo in 2004 of 100,000 shares each, resulting
in the recording of $11,000 (six months) of additional stock compensation
expense, and (iv) accelerated the vesting of a direct stock grant issued to
Daryl Mazzanti in June 2005, resulting in $20,112 (six months) of additional
stock compensation expense.
In August 2005, we granted options to purchase 28,000 shares of common stock
with an exercise price equal to the market price of the underlying common stock,
to each of two independent board members. The options have a ten year life and a
one year vesting term. In addition, we granted 130,000 options to two employees
with an exercise price equal to the market price of the underlying common stock
as of the date of grant. They have a ten year life and a four year vesting term.
During the six months ended December 31, 2004, we granted options to purchase up
to an aggregate total of 200,000 shares of common stock with an exercise price
of $1.27 per share (in the money), to each of our two independent board members,
Messrs. Gene Stoever and E. J. DiPaolo (or 100,000 shares each). The options
have a ten year life and vest over a two year period beginning May 26, 2004, the
date of the directors' election to the Board of directors.
Unless otherwise noted, all stock options mentioned above were granted under the
2004 Stock Plan.
The following tables illustrate the effect on net loss and loss per share for
the three and six months ended December 31, 2005 and 2004, as if we had applied
the fair value recognition provisions of SFAS No. 123 to stock-based employee
compensation. Fair value was calculated using the Black-Scholes option pricing
model.
Three Months Ended
December 31
--------------------------
2005 2004
----------- ------------
Pro forma impact of Fair Value Method (SFAS 148):
Net loss attributable to common stockholders, as
reported $ (541,884) $ (473,207)
Plus compensation expense determined under
Intrinsic Value Method (APB 25) 73,996 64,828
Less compensation expense determined under
Fair Value Method (372,074) (126,306)
----------- ------------
Pro forma net loss attributable to common
stockholders $ (839,962) $ (534,685)
Loss per share (basic and diluted):
As reported $ (0.02) $ (0.02)
Pro Forma $ (0.03) $ (0.02)
Six Months Ended
December 31
--------------------------
2005 2004
----------- ------------
Pro forma impact of Fair Value Method (SFAS 148):
Net loss attributable to common stockholders, as
reported $(1,341,943) $ (775,843)
Plus compensation expense determined under
Intrinsic Value Method (APB 25) 116,880 111,120
Less compensation expense determined under
Fair Value Method (628,431) (157,298)
----------- ------------
Pro forma net loss attributable to common
stockholders $(1,853,494) $ (822,021)
Loss per share (basic and diluted):
As reported $ (0.05) $ (0.03)
Pro Forma $ (0.07) $ (0.04)
7
Warrants
Pursuant to our amended agreement with Prospect, we issued revocable warrants to
purchase 200,000 shares of our common stock, exercisable at $1.36 per share over
five years. The warrants will be automatically revoked in the event we achieve
$200,000 in EBITDA, as defined, for any one month period through April 30, 2006.
Using the Black-Scholes model to compute fair value, a non-recurring charge of
$32,509 was recorded to interest expense for the three months ended September
30, 2005. The following assumptions were used in the calculation: term = 2.33
years, volatility = 140%, discount rate = 4.55%, and a 20% probability that the
warrants will not be revoked.
The shares of common stock issuable upon exercise of the Prospect Warrants are
subject to a registration rights agreement, pursuant to which we have granted
the holder certain piggyback registration rights.
During the six months ended December 31, 2005, 7,000 warrants were exercised by
two non-employees, resulting in the issuance of 3,758 shares of our common
stock. The remaining 3,242 warrants were cancelled as part of a cashless
exercise of the subject warrants.
Pursuant to a revocable warrant agreement we extended to our Vice President of
Operations at the beginning of his employment requiring certain performance
measures which were met as of December 12, 2005, thereby establishing a
measurement and beginning vesting date for purposes of computing compensation
expense for the pro forma tables provided in this Note 6 above.
During the six months ended December 31, 2004, no warrants were issued or
granted.
7. Commodity Hedging and Price Risk Management Activities
Pursuant to the terms of the Prospect Facility, we entered into financial
instruments covering approximately 50% of our expected oil and gas production
from proved developed producing properties over the next two years. We used
reserve report data prepared by W. D. Von Gonten & Co., our independent
petroleum engineering firm, to estimate our future production for hedging
purposes. As we may elect under FAS 133, Accounting for Derivative Instruments
and Hedging Activities, we have designated our physical delivery contracts as
normal delivery sale contracts. For the oil price floors (the "Puts") we
purchased, we have not fulfilled the documentation requirements of FAS 133. As a
result, the Put contracts are "marked-to-market", with the unrealized gain or
loss reflected in our statement of operations. At December 31, 2005, we had the
following financial instruments in place:
(i) 2,100 Bbls of oil to be delivered monthly from March 2005 through
February 2006 to Plains Oil Marketing LLC, at $48.35 per barrel,
plus or minus changes in basis between: (a) the arithmetic daily
average of the prompt month "Light Sweet Crude Oil" contract
reported by the New York Mercantile Exchange, and (b) Louisiana
field posted price. This is accounted for as a normal delivery sales
contract. This contract was extended for the months of March 2006
through May 2006 for 70 Bbls of oil per day at a fixed price of
$52.55 per barrel of oil, and extended again for the months of June
2006 through August 2006 for 90 Bbls of oil per day at a fixed price
$63.45 per barrel of oil.
(ii) 100 Mcfd of natural gas at a fixed price of $6.21, delivered through
our Delhi Field sales tap into Gulf South's pipeline, for the
account of Texla for deliveries from March 2005 to May 2006. This is
accounted for as a normal delivery sales contract.
(iii) Purchase of a non-physical Put contract at $38 per barrel for 2,000
Bbls of crude oil production from March 2006 through February 2007.
This is accounted for as a "mark-to-market" derivative investment.
For the six months ended December 31, 2005, $6,902 was expensed to
reflect the changes in the market value of the Put from June 30,
2005 to December 31, 2005.
For the six months ended December 31, 2004, there were no financial instruments
in place.
8
8. Related Party Transactions
Laird Q. Cagan, Chairman of our Board, is a Managing Director and co-owner of
Cagan McAfee Capital Partners, LLC ("CMCP"). CMCP performs financial advisory
services to us pursuant to a written agreement, earning a monthly retainer of
$15,000. In addition, Mr. Cagan, as a registered representative of Chadbourn
Securities, Inc. ("Chadbourn"), has served as the Company's placement agent in
private equity financings, typically earning cash fees equal to 8% of gross
equity proceeds and warrants equal to 8% of the shares purchased, exercisable
over seven years, net of any similar payments made to third parties.
In December 2005, we renegotiated our agreement with CMCP, and the monthly
retainer fee has decreased from $15,000 per month to $5,000 per month effective
December 1, 2005. The retainer includes payment for the services of Mr. Cagan as
Chairman of our Board.
For the three months ended December 31, 2005, $30,000 was paid to CMCP, $20,000
was expensed and $10,000 was reclassified as a Prepaid Asset for future retainer
fees (namely January and February 2006).
For the three months ended September 30, 2005, $45,000 was expensed and paid to
CMCP.
During the three months ended December 31, 2004, $45,000 was expensed as monthly
retainer fees to CMCP, and payment was made in May 2005. In addition, Mr. Cagan
and Chadbourn earned $17,840 for the placement of 194,200 shares of our common
stock. Furthermore, we issued warrants to purchase up to a total of 12,536
shares of common stock to Mr. Cagan and Chadbourn. These warrants have a $1.50
exercise price and a seven-year term. Mr. Cagan loaned us $445,000 as a partial
bridge financing for our acquisition in the Tullos Field Area and for additional
working capital purposes. This bridge loan was paid off in full, including
interest, in February 2005.
During the three months ended September 30, 2004, we expensed $45,000 in monthly
retainers to CMCP and payment was made in May 2005. Also during this period, we
charged $27,500 to stockholders' equity as a reduction of the proceeds from
common stock sales placed by Mr. Cagan and Chadbourn, and issued warrants to
purchase up to a total of 17,700 shares of common stock to Mr. Cagan and
Chadbourn in connection with the placement of our common shares. These warrants
were issued with a $1.50 exercise price and a seven-year term. Mr. Cagan loaned
us $475,000 as a partial bridge financing for our first acquisition in the
Tullos Field Area and for additional working capital purposes. This bridge loan
was paid off in full, including interest, in February 2005.
Eric A. McAfee, a major shareholder of the Company and also a Managing Director
of CMCP, has served as Vice Chairman of the Board of Verdisys, Inc., the
provider of certain horizontal drilling services to the Company. Subsequently in
2004, Mr. McAfee resigned from the Board of Directors of Verdisys, but continues
to hold shares in both companies. Mr. McAfee has represented to the Company that
he is also a 50% owner of Berg McAfee Companies, LLC, which owns approximately
30% of Verdisys, Inc. NGS paid $25,960 to Verdisys (Blast Energy) during 2004
for horizontal drilling services.
John Pimentel, a former member of our Board of Directors, is a principal with
CMCP.
9. Liquidity and Capital Resources
At December 31, 2005, we had $433,465 of unrestricted cash and positive working
capital of $619,025, as compared to $2,548,688 of unrestricted cash and positive
working capital of $2,599,232 at June 30, 2005, and $91,563 of unrestricted cash
and negative working capital of $1,349,315 at December 31, 2004. In calendar
2005, our working capital was positively impacted by the $3,000,000 of gross
proceeds we received from the sale of our common stock in May of 2005, and the
re-financing of our short-term debt with long-term debt and equity under the
Prospect Facility in February 2005.
An amendment to the Prospect Facility dated September 22, 2005 was effected in
order to allow us to proceed with the delayed drilling program of proved
undeveloped reserve locations in our Delhi Field, the results of which we are
relying on to achieve the EBITDA coverage ratio required of us by Prospect. The
timely drilling and production of our proved undeveloped reserves, based on the
reserve report prepared by W.D. Von Gonten & Co dated July 1, 2005, will be
necessary to provide sufficient additions to earnings to comply with Prospect's
EBITDA coverage ratio and sufficient cash to maintain our operations for at
least the next twelve months. Although the 2005 Delhi Development Drilling
Program has been substantially completed, we can give no assurance that the
assumptions in the reserve report will be achieved or that the wells will be
completed and placed onto production in the timely manner necessary to comply
with Prospect's EBITDA covenant coverage. If such a covenant breach occurs and
is not waived by Prospect, the debt would become immediately due and payable.
Since we do not have sufficient liquid assets to prepay our debt in full, we
would be required to refinance all or a portion of our existing debt or obtain
additional financing. If we were unable to refinance our debt or obtain
additional financing, we would be required to curtail portions of our
development program, sell assets, and/or reduce capital expenditures. Had we
been subject to the interest coverage test at December 31, 2005, we would not
have been in compliance.
10. Subsequent Events
On January 13, 2006, we entered into a Securities Purchase Agreement with
Rubicon Master Funds ("Rubicon"), wherein we issued Rubicon 160,000 additional
shares of our common stock as consideration for amending and restating our
Registration Rights Agreement dated as of May 6, 2005. The amended terms removed
our obligation to pay monetary damages for our failure to obtain and maintain an
effective
9
registration statement including their shares, although we are still required to
use our best commercial efforts to register for resale the 160,000 shares issued
to Rubicon, along with the 1.2 million shares previously issued them.
On January 24, 2006 we filed Amendment No. 2 to our Form SB-2 originally filed
with Securities and Exchange Commission ("SEC") on June 6, 2005, and amended on
October 19, 2005. Amendment No. 2 was filed to include additional information in
response to the SEC's comment letter to us dated November 18, 2005. The SEC is
currently reviewing the amended registration statement and we can give no
assurance that our registration statement will become or be maintained
effective.
On January 27, 2006 we extended our crude oil hedging contracts with Plains Oil
Marketing, LLC for an additional six months, covering the periods September 2006
through February 2007. The contract requires us to deliver 2,700 Bbls of oil per
month, in exchange for a fixed price of $69.30 per Bbl, plus or minus NYMEX to
posted field price basis risk.
On January 31, 2006, we acquired an additional net revenue interest in one of
our existing fields. Funding of the $1 million purchase price was provided by an
additional $1 million advance under our Prospect Facility, thereby increasing
the maturity value of our note due them at maturity to $5 million, and the
issuance of an additional 150,000 of irrevocable warrants and 100,000 of
revocable warrants, exercisable over five years at the 20 trading day average
price immediately prior to January 31 2006. The revocable warrants can be
revoked by the Company at any time that cash basis EBITDA reaches or exceeds
$200,000 in any one month prior to June 1, 2006.
On February 13, 2006 we amended our existing agreements with Cagan McAfee
Capital Partners, LLC and Chadbourn Securities, Inc.
Laird Q. Cagan, the Chairman of our Board of Directors, is a Managing Director
of Cagan McAfee Capital Partners, LLC ("CMCP"). Under the revised terms of the
agreement with CMCP (the "CMCP Agreement"), CMCP shall continue to perform
management advisory services for us for an additional year, starting December 1,
2005, and receive a monthly retainer of $5,000, which includes the services of
Mr. Cagan as Chairman of the Board.
In addition, Mr. Cagan is a registered representative of Chadbourn Securities,
Inc. ("Chadbourn"), our non-exclusive placement agent for private financings.
Under the revised terms of our agreement with Chadbourn (the "Chadbourn
Agreement"), in connection with placement agent services Chadbourn shall earn
cash fees of up to 8% (decreasing with private placements exceeding $1 million)
and warrants equal to 4% of the number of shares sold in equity offerings at
an exercise price equal to the offering price. In addition, Chadbourn shall
receive a 2% placement fee for special purpose vehicle and/or debt financings.
Finally, Chadbourn shall earn a merger & acquisition advisory fee equal to 1% of
the consideration paid in a merger or acquisition transaction. This agreement
has a one year term, starting December 1, 2005.
A copy of the CMCP Agreement and the Chadbourn Agreement are attached hereto as
Exhibits 10.1 and 10.2, respectively, and are incorporated herein by reference.
The foregoing summary does not purport to be complete and is qualified in its
entirety by reference to the CMCP Agreement and the Chadbourn Agreement.
On November 17, 2005, a class action lawsuit was filed in the Fifth Judicial
District Court, Richland Parish, Louisiana, against a number of defendants,
including two of the Company's subsidiaries, Arkla Petroleum L.L.C. ("Arkla")
and NG Sub Corporation (together with Arkla, the "Subsidiaries"). The
Subsidiaries were not served with the lawsuit until February 2006. The
plaintiffs claim to be landowners whose property (including the soil, surface
water, and groundwater) has been contaminated by oil and gas exploration, and
production and development activities conducted by the defendants on the
plaintiffs' property and adjoining land, since the 1930s (including activities
on the Delhi Field, which Arkla first began to operate in 2002 and which was
acquired by the Company in 2003). The plaintiffs claim that the defendants knew
of the alleged dangerous nature of the contamination and actively concealed it
rather than remedy the problem.
The plaintiffs are seeking unspecified compensatory damages and punitive
damages, as well as an order that the defendants restore the property and
prevent further contamination. The Company's ultimate exposure related to this
lawsuit is not currently determinable, but could, if adversely determined, have
a material adverse effect on the Company's financial condition. The costs to the
Company to defend this action could also have a material adverse effect on the
Company's financial condition.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This Form 10-QSB and the information referenced herein contain forward-looking
statements. The words "plan," "expect," "project," "estimate," "assume,"
"believe," "anticipate," "intend," "budget," "forecast," "predict" and other
similar expressions are intended to identify forward-looking statements. These
statements appear in a number of places and include statements regarding our
plans, beliefs or current expectations, including the plans, beliefs and
expectations of our officers and directors. We use the terms, "NGS," "Company,"
"we," "us" and "our" to refer to Natural Gas Systems, Inc. When considering any
forward-looking statement, you should keep in mind the risk factors that could
cause our actual results to differ materially from those contained in any
forward-looking statement. Important factors that could cause actual results to
differ materially from those in the forward-looking statements herein include
the timing and extent of changes in commodity prices for oil and gas, operating
risks and other risk factors as described in our 2005 Annual Report on Form
10-KSB and Form 10-KSB/A as filed with the Securities and Exchange Commission.
Furthermore, the assumptions that support our forward-looking statements are
based upon information that is currently available and is subject to change. We
specifically disclaim all responsibility to publicly update any information
contained in a forward-looking statement or any forward-looking statement in its
entirety and therefore disclaim any resulting liability for potentially related
damages. All forward-looking statements attributable to Natural Gas Systems,
Inc. are expressly qualified in their entirety by this cautionary statement.
Overview
Natural Gas Systems, Inc. is a petroleum company engaged primarily in the
acquisition, exploitation and development of properties for the production of
crude oil and natural gas from underground reservoirs. We acquire established
oil and gas properties and exploit them through the application of conventional
and specialized technology to increase production, ultimate recoveries, or both.
We conduct operations through our 100% working interests in the Delhi Field and
Tullos Field Area, located in Louisiana.
Critical Accounting Policies
Our 2005 Annual Report on Form 10-KSB and Form 10-KSB/A describes the accounting
policies that we believe are critical to the reporting of our financial position
and operating results and that require management's most difficult, subjective
or complex judgments.
This Quarterly Report on Form 10-QSB should be read in conjunction with the
discussion contained in our 2005 Annual Report on Form 10-KSB and Form 10-KSB/A
regarding these critical accounting policies.
Other Factors Affecting Our Business and Financial Results
In addition to the matters discussed above, our business, financial condition
and results of operations are affected by a number of other factors.
This Quarterly Report on Form 10-QSB should be read in conjunction with the
discussion in our 2005 Annual Report on Form 10-KSB and Form 10-KSB/A regarding
these other risk factors.
Results of Operations
Summary
We have continued our growth in critical metrics of production and revenues
while limiting our cash overhead costs. In the most recent three and six month
periods, our sales volumes have increased by 93% or more, and our revenues have
increased by 127% or more over the comparable periods of 2004. Key
considerations in this growth are:
o The Tullos Area properties we purchased from Atkins as of September 1,
2004 only contributed production and revenues for four of the six months
ended December 31, 2004, as compared to a six month contribution during
the six months ended December 31, 2005;
10
o The Tullos Area properties we purchased from Chadco as of February 1, 2005
contributed no production or revenues during the six months ended December
31, 2004, as compared to a six month contribution during the six months
ended December 31, 2005; and
o Only one of our five 2005 Delhi Development Drilling Program wells, the
Delhi 92-2, was completed soon enough to make a meaningful revenue
contribution in the three months ended December 31, 2005, and then for
only the last half of the period.
Our most significant development activity to date has been the implementation of
our 2005 Delhi Development Drilling Program that was originally scheduled to
begin in May 2005 and was delayed until the second week of October, 2005 by the
drilling contractor. By December 31, 2005, three PUD wells in our 2005 Delhi
Development Drilling Program had been completed and were producing. The fourth
well had been drilled by year end, and was completed and put onto production in
late January 2006. The fifth well, a PUD, had been drilled and completed, and
was put onto production in early February, 2006.
Of particular significance, the fourth well drilled and completed, the Delhi
225-2, was an unproved location that we elected to drill ahead of other proved
locations. The results of that well will add to our proved producing reserves
and we believe should lead to one or more proved undeveloped locations in the
same reservoir that could hold substantial reserves.
During the period ended December 31, 2005, only one of the five wells we drilled
and completed, was producing mostly due to poor drilling practices by the
drilling contractor, delays in drilling due to breakdowns in rig equipment,
contractor crew turnover and resulting oil-water emulsions and paraffin
blockages created in the reservoir. The oil-water emulsions and paraffin
blockages have been alleviated, in part, through chemical treatments, and
additional work is anticipated to further increase production. We believe that
February 2006 will be the first month to include production from all five
drilled and completed wells.
The sixth and seventh wells previously anticipated to be drilled in our 2005
Delhi Development Drilling Program have been rescheduled for later in 2006 due
to unfavorable ground conditions resulting from heavy rains in early January in
the area and the significant financial costs of putting the drilling rig on
standby. Consequently, the drilling rig was released in early January 2006 as a
cost saving measure. We are in negotiations with another contractor for a
drilling rig to initiate our 2006 Delhi Development Drilling Program. The sixth
and seventh wells from the 2005 program are expected to be included in our 2006
drilling program.
Going forward, our objectives for calendar year 2006 are to:
o Continue increasing our net property values (net present value in excess
of our costs) through re-investments in infrastructure, work-overs,
recompletions, water disposal capacity and new development drilling, at
the potential cost of reduced near term cash flows and earnings; and
o Ultimately increase our margins, net cash flows and earnings by:
o Increasing production and revenues
o Controlling cash G&A expense to a growth rate slower than our
revenue growth
o Maintaining or reducing field operating expense per BOE
o Seek additional oil & gas property acquisitions.
Three months ended December 31, 2005 compared to three months ended December 31,
2004
The following table sets forth certain financial information with respect to our
oil and gas operations.
Three Months Ended
December 31
--------------------
Net to NGS 2005 2004 Variance % change
--------- --------- --------- ---------
Sales Volumes:
Oil (Bbl) 11,827 5,263 6,564 125%
Gas (Mcf) 24,109 15,860 8,249 52%
Oil and Gas (Boe) 15,845 7,906 7,940 100%
Revenue data (a):
Oil revenue $ 551,981 $ 250,931 $ 301,050 120%
Gas revenue 278,955 114,837 164,118 143%
--------- --------- ---------
Total oil and gas revenues $ 830,936 $ 365,768 $ 465,168 127%
Average prices (a):
Oil (per Bbl) $ 46.67 $ 47.68 $ (1.01) -2%
Gas (per Mcf) 11.57 7.24 4.33 60%
Oil and Gas (per Boe) 52.44 46.26 6.18 13%
Expenses (per BOE)
Lease operating expenses and
production taxes $ 26.52 $ 26.05 $ 0.47 2%
DD&A expense on oil and gas
properties 7.16 6.88 0.28 4%
(a) Includes the cash settlement of hedging contracts
11
Net loss. For the three months ended December 31, 2005, we reported a net loss
of $541,884 or $0.02 loss per share on total revenues of $830,936, as compared
with a net loss of $473,207 or $0.02 loss per share on total revenues of
$365,768 for the three months ended December 31, 2004. The increase in losses is
attributable to increases in lease operating and general and administrative
expenses, high workover costs in October 2005 and losses on lender required
price hedges, partially offset by increases in revenues due to higher sales
volumes and sales prices. Excluding non-cash stock compensation expense of
$156,277 and non-cash penalty expense of $114,239 for not obtaining an effective
registration statement, our net loss for the three months ended December 31,
2005 was $271,368, or $0.01 loss per share. By comparison, after excluding
non-cash stock compensation expense of $64,828 for the three months ended
December 31, 2004, our net loss was $408,379, or $0.017 loss per share.
Sales Volumes. Oil sales volumes, net to our interest, for the three months
ended December 31, 2005 increased 125% to 11,827 Bbls, compared to 5,263 Bbls
for the three months ended December 31, 2004. 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 and recompletions in our portfolio. The five wells
we drilled and completed did not contribute materially to oil sales during the
three months ended December 31, 2005.
Net natural gas volumes sold for the three months ended December 31, 2005 were
24,109 Mcfs, an increase of 52% from the three months ended December 31, 2004.
Gas volumes increased primarily due to the 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 December 31, 2005 increased 115% to 11,860 Bbls, compared
to 5,524 Bbls for the three months ended December 31, 2004. This is primarily
due to the acquisition of wells in the Tullos Field Area and general field
development opportunities. The five wells we drilled and completed did not
contribute materially to oil production during the three months ended December
31, 2005. Net natural gas production for the three months ended December 31,
2005 increased 38% to 29,203 Mcfs, compared to 21,161 Mcfs for the three months
ended December 31, 2004. This increase was due to a new well drilled in November
2005, the Delhi 92-2.
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 127% for the three month period ended December
31, 2005, compared to the same period in 2004, as a result of the 100% increase
in sales volumes due to the Chadco acquisition of producing leases in the Tullos
Field Area and additional natural gas sales from the 92-2 well which was
completed and began production in November 2005. Another component of the
increase was a 13% increase in the sales prices we received per BOE during the
three months ended December 31, 2005 as compared to the three months ended
December 31, 2004.
Lease Operating Expenses. Lease operating expenses for the three months ended
December 31, 2005 increased $205,217 from the comparable 2004 period to
$398,686. The increase in operating expenses in 2005 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, and (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.
General and Administrative Expenses. General and administrative expenses
(exclusive of non-cash stock compensation expense of $156,277 and penalty
expense of $114,239) was $391,590 for the three months ended December 31, 2005,
a decrease of $84,151 from $475,741 (exclusive of non-cash stock compensation
expense of $64,828), for the three months ended December 2004. Overall general
and administrative expenses were higher in the prior year due to significant
start up 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
$59,457 for the three months ended December 31, 2005 to $113,443 from $53,986
for the same period in 2004. The increase is primarily due to a 100% increase in
sales volumes and a 4% increase in the average depletion rate, period over
period.
Interest Expense. Interest expense for the three months ended December 31, 2005
increased $149,914 to $191,016 (of which $141,151 was cash expense) compared to
$41,102 (of which $6,370 was cash expense) for the three months ended December
31, 2004. The increase in interest expense was primarily due to interest expense
associated with the Prospect Facility, which was not outstanding in the 2004.
The non-cash portion of interest expense is associated with amortization of the
discount we assigned to the Prospect note, based on the fair value we attributed
to the granting of the warrants to Prospect.
12
Six months ended December 31, 2005 compared to six months ended December 31,
2004
Six Months Ended
December 31
-----------------------
Net to NGS 2005 2004 Variance % change
---------------------------- ---------- ---------- ---------- ----------
Sales Volumes:
Oil (Bbl) 20,781 9,202 11,579 126%
Gas (Mcf) 33,959 27,117 6,842 25%
Oil and Gas (Boe) 26,441 13,722 12,720 93%
Revenue data (a):
Oil revenue $1,036,932 415,454 $ 621,478 150%
Gas revenue 336,888 181,481 155,407 86%
---------- ---------- ----------
Total oil and gas revenues $1,373,820 $ 596,935 $ 776,885 130%
Average prices (a):
Oil (per Bbl) $ 49.90 $ 45.15 $ 4.75 11%
Gas (per Mcf) 9.92 6.69 3.23 48%
Oil and Gas (per Boe) 51.96 43.50 8.45 19%
Expenses (per Boe)
Lease operating expenses and
production taxes $ 34.00 $ 26.22 $ 7.78 30%
DD&A expense on oil and gas
properties 7.16 6.88 0.28 4%
(a) Includes the cash settlement of hedging contracts
13
Net Loss. For the six months ended December 31, 2005, we reported a net loss of
$1,341,943 or $0.05 loss per share on total revenues of $1,373,820, as compared
with a net loss of $775,843 or $0.03 loss per share on total revenues of
$596,935 for the six months ended December 31, 2004. The increase in losses are
attributable to overall increases in lease operating and general and
administrative expenses, partially offset by increases in revenues due to higher
sales volumes and sales prices. Excluding non-cash stock compensation expense of
$269,351 and non-cash penalty expense of $114,239 for not having obtained an
effective registration statement, our net loss for the six months ended December
31, 2005 was $958,353, or $0.04 loss per share. By comparison, excluding
non-cash stock compensation expense of $111,121 for the six months ended
December 31, 2004, our net loss was $664,722, or $0.03 loss per share.
Sales Volumes. Oil sales volumes, net to our interest, for the six months ended
December 31, 2005 increased 126% to 20,781 Bbls, compared to 9,202 Bbls for the
six months ended December 31, 2004. 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 and recompletions in our portfolio.
Net natural gas volumes sold for the six months ended December 31, 2005 were
33,959 Mcfs, an increase of 25% from the six months ended December 31, 2004. Gas
volumes increased primarily due to the Delhi 92-2 well which was drilled in
October 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 six months ended December 31, 2005 increased 140% to 22,500 Bbls, compared
to 9,375 Bbls for the six months ended December 31, 2004. This is primarily due
to the acquisition of wells in the Tullos Field Area and general field
development opportunities.
Our net oil stock ending inventory increased approximately 80% at December 31,
2005 to approximately 4,300 Bbls, as compared to approximately 2,400 Bbls at
December 31, 2004. Increases in oil inventory were attributable to additional
producing wells (and tank batteries) acquired in the Chadco acquisition and
approximately 1,600 barrels of oil that were not picked up by our crude oil
purchaser for sale by December 31, 2005. Since many of these leases do not make
a full truckload within one month (one truckload equals ~ 160 Bbls), the Tullos
Field Area tends to maintain higher levels of inventory compared to production,
and can cause erratic oil runs due to the preference of our oil purchaser to
gather a full truckload from a single tank battery.
Net natural gas production for the six months ended December 31, 2005 increased
16% to 43,570 Mcfs, compared to 37,521 Mcfs for the six months ended December
31, 2004. This increase was due to a new well drilled in November 2005, the
Delhi 92-2, offset by well downtime caused by mechanical problems on the Delhi
184-2 well, shut-in of our gas gathering line to repair line leaks and normal
production declines.
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.
14
Oil and gas revenues increased 130% for the six month period ended December 31,
2005, compared to the same period in 2004, as a result of a 93% 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,
including the gas production from our recently drilled Delhi 92-2 well. Another
component of the increase was a 19% increase in the average sales prices we
received per BOE during the six months ended December 31, 2005 as compared to
the six months ended December 31, 2004.
Lease Operating Expenses. Lease operating expenses for the six months ended
December 31, 2005 increased $531,659 from the comparable 2004 period to
$862,876. The increase in operating expenses in 2005 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, and (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.
On a BOE basis, lease operating expense and production taxes totaling $34.00 per
BOE did not meet our expectations for the six months ended December 31, 2005, as
compared to 2004's comparable period of $26.22. 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. Following its recompletion last year into
a new reservoir with an initial flowing production rate of 90 bopd, it suffered
a casing collapse, causing us to engage in numerous expensive workovers that
eventually enabled us to produce the well at a constrained rate of 30+ bopd.
General and Administrative Expenses. General and administrative expenses
(exclusive of non-cash stock compensation expense of $269,351 and penalty
expense of $114,239) was $862,794 for the six months ended December 31, 2005, an
increase of $122,211 as compared to $740,583 (exclusive of non-cash stock
compensation expense of $111,121) for the comparable 2004 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, D&O
insurance, outside director fees and other related costs.
Depletion and Amortization Expense. Depletion and amortization expense increased
$88,256 for the six months ended December 31, 2005 to $189,348 from $101,092 for
the same period in 2004. The increase is primarily due to a 93% increase in
sales volumes and a 4% increase in the average depletion rate, period over
period.
Interest Expense. Interest expense for the six months ended December 31, 2005
increased $346,326 to 412,694 (of which $282,516 was cash expense) compared to
$66,368 (of which $18,452 was cash expense) for the six months ended December
31, 2004. The increase in interest expense was primarily due to interest expense
associated with the Prospect Facility, which was not outstanding in the
comparable period in 2004. In addition, $32,509 was recorded as a non-recurring
charge to interest expense, representing the fair value of 200,000 revocable
warrants issued in consideration to amend the Prospect Facility on September 22,
2005.
Hurricane Update. On August 29, 2005, Hurricane Katrina, came onshore just east
of New Orleans, LA. None of our oil and gas properties suffered casualty losses
from this storm. On September 24, 2005, Hurricane Rita came onshore near the
Texas/Louisiana border and headed north near our oil and gas operations in
Northern Louisiana. None of our oil and gas properties suffered casualty losses
from this storm, except we experienced approximately two days of deferred
production at our Tullos Field, due to sporadic electricity outages.
Liquidity and Capital Resources
At December 31, 2005, we had $433,465 of unrestricted cash and positive working
capital of $619,025, as compared to $2,548,688 of unrestricted cash and positive
working capital of $2,599,232 at June 30, 2005, and $91,563 of unrestricted cash
and negative working capital of $1,349,315 at December 31, 2004. In 2005, our
working capital was positively impacted by the $3,000,000 of gross proceeds we
received from the sale of our common stock in May of 2005, and the re-financing
of our short-term debt with long-term debt and equity under the Prospect
Facility in February 2005.
Effective September 22, 2005, we entered into an amendment to the Prospect
Facility, thereby obtaining covenant relief with respect to our obligation to
maintain an EBITDA to interest payable coverage ratio of 2.0:1. The amendment
changes our compliance date to begin not later than the three months ended
January 31, 2006, as compared to October 31, 2005 under the original terms of
the agreement. In consideration for the amendment, we have issued to Prospect
revocable warrants to purchase 200,000 shares of our common stock, exercisable
at $1.36 per share over five years. As a result, a non-recurring charge of
$32,509 was recorded to interest expense during the three months ended September
30, 2005. The warrants will be automatically revoked in the event we achieve
$200,000 in EBITDA, as defined, for any one month period through April 30, 2006.
We also agreed to limit our acquisitions of additional oil and gas properties to
a maximum of $100,000 plus any new funds raised, until we achieve a trailing
three month EBITDA to interest coverage ratio of 2.0:1. The limitation does not
include any evaluation costs, so that we may continue to review new projects.
15
The amendment to the Prospect Facility was effected in order to allow us to
proceed with the delayed drilling program of proved undeveloped reserve
locations in our Delhi Field, the results of which we are relying on to achieve
the EBITDA coverage ratio required of us by Prospect. The timely drilling and
production of our proved undeveloped reserves, based on the reserve report
prepared by W.D. Von Gonten & Co dated July 1, 2005, will be necessary to
provide sufficient additions to earnings to comply with Prospect's EBITDA
coverage ratio, and will provide sufficient cash to maintain our operations for
at least the next twelve months. Although the 2005 Delhi Development Drilling
Program has been substantially completed, we can give no assurance that the
assumptions in the reserve report will be achieved or that the wells will be
completed and placed onto production in the timely manner necessary to comply
with Prospect's EBITDA covenant coverage. If such a covenant breach occurs and
is not waived by Prospect, the debt would become immediately due and payable.
Since we do not have sufficient liquid assets to prepay our debt in full, we
would be required to refinance all or a portion of our existing debt or obtain
additional financing. If we were unable to refinance our debt or obtain
additional financing, we would be required to curtail portions of our
development program, sell assets, and/or reduce capital expenditures. Had we
been subject to the interest coverage test at December 31, 2005, we would not
have been in compliance.
We have historically financed our development activities through proceeds from
debt and equity proceeds. In the short term we intend to finance our current
development drilling program through our existing working capital resources. As
operator of all of our projects in development, we have the ability to
significantly control the timing of most of our capital expenditures. We believe
the cash flows from operating activities, combined with our ability to control
the timing of substantially all of our future development and acquisition
requirements, will provide us with the flexibility and liquidity to meet our
future planned capital requirements through the next twelve months.
Cash used in operating activities for the six months ended December 31, 2005 was
$804,698 and cash used in operations for the comparative period in 2004 was
$68,455. In 2005, the increase in cash used in operating activities was
primarily due to higher operating expenses, partially offset by higher revenues.
Cash used in investing activities in the six months ended December 31, 2005 and
2004 was $1,303,771 and $938,915, respectively. In 2005, the majority of the
development capital expenditures were spent on the 2005 Delhi Development
Drilling Program. For the six months ended December 2004, we expended
approximately $725,000 in capital acquisition costs for the purchase of
producing properties in our Tullos Field Area, and approximately $215,000 was
used for development capital in our existing portfolio.
Cash used in financing activities for the six months ended December 31, 2005 was
$6,754, which was used to pay off the remaining note for property insurance.
Comparatively, $731,102 was used in the 2004 period which consisted of $977,875
in net proceeds from loans and $529,199 of gross cash proceeds from the private
sale of 369,200 shares of our common stock, before commissions, less $775,972
used for loan repayments.
Budgeted Capital Expenditures. Our 2005 Delhi Development Drilling Program began
in early October, 2005. As of January 26, 2006 we had drilled and completed four
wells and drilled and logged one other well. We estimate that capital
expenditures approximating $1.3 million, provided from our working capital, will
be necessary for the drilling and completion of these five wells. 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. We anticipate that
these wells will be combined with other locations to comprise our 2006 Delhi
Development Drilling Program, to commence later in calendar year 2006. Budgeting
for our 2006 plan is in progress.
ITEM 3. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed in our Exchange Act reports is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission's rules and forms and that such information
is accumulated and communicated to this company's management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
for 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.
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out
an evaluation, under the supervision and with the participation of the Company's
management, including our Chief Executive Officer and the Company's Chief
Financial Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures as of the end of the quarter covered by this
report. Based on the foregoing, our Chief Executive Officer and Chief Financial
Officer concluded that our disclosure controls and procedures are effective in
ensuring that the information required to be disclosed in our reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission
rules and forms.
There has been no change in our internal control over financial reporting during
our most recent fiscal quarter that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
16
PART II - OTHER INFORMATION
ITEMS 2, 3 AND 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED
ITEM 1. Litigation
On November 17, 2005, a class action lawsuit was filed in the Fifth
Judicial District Court, Richland Parish, Louisiana, against 26 defendants,
including two of our subsidiaries, Arkla Petroleum L.L.C. ("Arkla") and NGS Sub.
Corp. (together with Arkla, the "Subsidiaries"). We were not served with the
lawsuit until February 2006.
The plaintiffs claim to be landowners whose property (including the soil,
surface water, and groundwater) has been contaminated by oil and gas
exploration, production and development activities conducted by the defendants
on the plaintiffs' property and adjoining land, since the 1930s (including
activities by Arkla as operator of the Delhi Field subsequent to Arkla's
formation in 2002 and our acquisition of Arkla in 2003, and activities since NGS
Sub. Corp.'s acquisition of a 100% working interest in the Delhi Field in
2003.). The plaintiffs claim that the defendants knew of the alleged dangerous
nature of the contamination and actively concealed it rather than remedy the
problem.
The plaintiffs are seeking unspecified compensatory damages and punitive
damages, as well as an order that the defendants restore the property and
prevent further contamination. Our ultimate exposure related to this lawsuit is
not currently determinable, but could, if adversely determined, have a material
adverse effect on our financial condition. Our costs to defend this action could
also have a material adverse effect on our financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The following matters were submitted to a vote of security holders
during Natural Gas System's Annual Meeting of Stockholders held on
December 1, 2005:
1. Election of Directors - The following nominees were elected to serve as
Directors of Natural Gas Systems, Inc. until the 2006 Annual Meeting of
Stockholders:
Votes Cast for Votes Withheld
-------------- --------------
Laird Q. Cagan 18,748,691 25,405
E. J. DiPaolo 18,749,591 24,505
William E. Dozier 13,374,000 0
Robert S. Herlin 18,749,491 24,605
Gene S. Stoever 18,749,591 24,505
2. Ratification of the appointment of Hein & Associates LLP, as independent
accountants:
For Against Abstain
---------- --------- -------
18,769,091 5,005 0
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
A. Exhibits
10.1 Agreement with Chadbourn Securities, Inc., dated February 13, 2006.
10.2 Agreement with Cagan McAfee Capital Partners, LLC, dated February
13, 2006.
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) under the Securities Exchange Act of 1934, as
amended.
31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) under the Securities Exchange Act of 1934, as
amended.
32.1 Certification of Chief Executive Officer pursuant Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended
and 18 U.S.C. Section 1350.
32.2 Certification of Chief Financial Officer pursuant Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended
and 18 U.S.C. Section 1350.
B. Reports on Form 8-K
Current Report on Form 8-K filed on October 7, 2005, pursuant to Item 1.01,
announcing the entry into a material definitive agreement.
17
SIGNATURES
In accordance with the requirements of the Securities Exchange Act of 1934, the
registrant caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
NATURAL GAS SYSTEMS, INC.
(Registrant)
Date: February 14, 2006 By: /s/ STERLING H. MCDONALD
------------------------------------------
Sterling H. McDonald
Chief Financial Officer
Principal Financial and Accounting Officer