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 September 30, 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
of incorporation or organization) identification no.)
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 November 1, 2005, was 24,778,364.
Transitional Small Business Disclosure Format (Check one): Yes: __ No: X
NATURAL GAS SYSTEMS, INC.
TABLE OF CONTENTS
Page
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets: September 30, 2005
(unaudited) and June 30, 2005 3
Consolidated Statements of Operations (unaudited):
For the three months ended September 30, 2005 and 2004 4
Consolidated Statements of Cash Flows (unaudited):
For the three months ended September 30, 2005 and 2004 5
Notes to Consolidated Financial Statements 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 9
ITEM 3. CONTROLS AND PROCEDURES 13
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS 14
SIGNATURES
PART I - FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED BALANCE SHEET
September 30, June 30,
2005 2005
----------- -----------
(unaudited)
Assets
Current Assets:
Cash $ 1,727,437 $ 2,548,688
Accounts receivable, trade 181,962 300,761
Inventories 489,189 222,470
Prepaid expenses 42,217 84,304
Retainers and deposits 56,335 56,335
----------- -----------
Total current assets 2,497,140 3,212,558
Oil & Gas properties - full cost 5,521,113 5,276,303
Oil & Gas properties - not amortized 77,378 61,887
Less: accumulated depletion (389,296) (313,391)
----------- -----------
Net oil & gas properties 5,209,195 5,024,799
Furniture, fixtures, and equipment, at cost 14,684 12,113
Less: accumulated depreciation (4,747) (3,401)
----------- -----------
Net furniture, fixtures, and equipment 9,937 8,712
Restricted deposits 864,145 863,089
Other assets 339,093 356,066
----------- -----------
Total assets $ 8,919,510 $ 9,465,224
=========== ===========
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable $ 359,278 $ 240,389
Accrued liabilities 144,032 176,470
Registration costs 94,500 100,000
Notes payable, current 0 6,754
Royalties payable 83,338 89,713
----------- -----------
Total current liabilities 681,148 613,326
Long term Liabilities:
Notes payable 4,000,000 4,000,000
Discount on notes payable (1,059,644) (1,093,452)
Asset retirement obligations 440,151 433,250
----------- -----------
Total liabilities 4,061,655 3,953,124
Stockholders' Equity:
Common Stock, par value $0.001 per share; 100,000,000 shares
authorized, 24,777,540 and 24,774,606 shares issued and outstanding
as of September 30, 2005 and June 30, 2005, respectively 24,777 24,774
Additional paid-in-capital 9,644,504 9,611,767
Deferred stock based compensation (482,209) (595,283)
Accumulated deficit (4,329,217) (3,529,158)
Total stockholders' equity 4,857,855 5,512,100
----------- -----------
Total liabilities and stockholders' equity $ 8,919,510 $ 9,465,224
=========== ===========
See accompanying notes to condensed consolidated financial statements.
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Three Months Three Months
Ended September Ended September
30, 2005 30, 2004
------------ ------------
(unaudited) (unaudited)
Revenues:
Oil sales $ 486,395 $ 164,523
Gas sales 57,933 66,644
Price risk management activities (1,444) 0
------------ ------------
Total revenues 542,884 231,167
Expenses:
Lease operating costs 464,190 137,748
Production taxes 14,484 16,024
Depreciation, depletion and amortization 77,250 47,106
General and administrative 584,278 311,135
------------ ------------
Total operating expenses 1,140,202 512,013
------------ ------------
Loss from operations (597,318) (280,846)
Other revenues and expenses:
Interest income 18,937 3,476
Interest expense (221,678) (25,266)
------------ ------------
Total other revenues and expenses (202,741) (21,790)
------------ ------------
Net loss $ (800,059) $ (302,636)
============ ============
Loss per common share, basic and diluted $ (0.03) $ (0.01)
Weighted average number of common shares,
basic and diluted 24,777,056 23,146,313
See accompanying notes to condensed consolidated financial statements
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
Three Months Three Months
Ended Ended
September 30, September 30,
2005 2004
----------- -----------
(unaudited) (unaudited)
----------- -----------
Cash flow from operating activities:
Net loss $ (800,059) $ (302,636)
Adjustments to reconcile net loss to net cash used by operating
activities:
Stock-based compensation 113,074 46,292
Depletion 75,905 47,106
Depreciation 1,345 386
Accretion of asset retirement obligation 6,901 3,270
Accretion of debt discount and non-cash interest 80,315 0
Changes in assets and liabilities:
Accounts receivable 118,799 (139,838)
Inventories (266,719) (28,143)
Accounts payable 118,889 139,506
Royalties payable (6,375) 0
Prepaid expenses 42,087 (1,029)
Accrued liabilities (37,938) 70,765
----------- -----------
Net cash used by operating activities (553,776) (164,321)
Cash flow from investing activities:
Capital expenditures for oil and gas properties (260,301) (805,523)
Capital expenditures for furniture, fixtures and equipment (2,571) 0
Restricted deposits and retainers (1,056) 0
Other assets 2,976 0
----------- -----------
Net cash used in investing activities (260,952) (805,523)
Cash flow from financing activities:
Proceeds from notes payable 0 481,597
Payments on notes payable (6,754) (350,716)
Proceeds from issuance of common stock 231 521,964
----------- -----------
Net cash provided by (used in) financing activities (6,523) 652,845
----------- -----------
Net decrease in cash (821,251) (316,999)
Cash and cash equivalents, beginning of period 2,548,688 367,831
----------- -----------
Cash and cash equivalents, end of period $ 1,727,437 $ 50,832
=========== ===========
Supplemental disclosure of cash flow information:
Interest paid $ 141,365 $ 12,082
See accompanying notes to condensed consolidated financial statements.
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 September 30, 2005, we
conduct operations through 100% working interests 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 months ended
September 30, 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 annual reporting
period that begins 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 September 30, 2005 is as follows:
Asset retirement obligation at June 30, 2005 $ 433,250
Liabilities incurred -
Liabilities settled -
Accretion expense 6,901
-----------
Asset retirement obligation at September 30, 2005 $ 440,151
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 is 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.
The following table sets forth the computation of basic and diluted earnings
(loss) per share:
Three months Three months
ended ended
September 30, September, 30
2005 2004
---------- ----------
Numerator:
Net loss applicable to common stockholders $ (800,059) $ (302,636)
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 $ (800,059) $ (302,636)
========== ==========
Denominator: 24,777,056 23,146,313
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 24,777,056 23,146,313
Net loss per common share, basic and diluted $ (0.03) $ (0.01)
========== ==========
5. Long-Term Debt
On February 3, 2005 we closed the "Prospect Facility" (or "Facility") and
ultimately borrowed $4,000,000, secured by all of our assets. At September 30,
2005, our book balance was $2,940,356, 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.
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, 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 Prospect. In consideration for the amendment, we 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, $32,509 of non-recurring fair value, as
determined using the Black-Scholes 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 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.
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
During the three months ended September 30, 2005, we granted stock options to
purchase 186,000 shares of our common stock, as described below:
In August 2005, we granted options to purchase 28,000 shares of common stock
with an exercise price equal to market price, 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 market price as of the date of grant. They have a ten year life and a
four year vesting term. All of these stock options were granted under our 2004
Stock Plan.
The following table illustrates the effect on net loss and loss per share for
the three months ended September 30, 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
September 30
--------------------------
2005 2004
----------- -----------
Pro forma impact of Fair Value Method (SFAS 148):
Net loss attributable to common stockholders, as reported $ (800,059) $ (302,636)
Plus compensation expense determined under Intrinsic Value Method (APB 25) 42,884 27,328
Less compensation expense determined under Fair Value Method (256,357) (30,992)
----------- -----------
Pro forma net loss attributable to common stockholders $(1,013,532) $ (306,300)
Loss per share (basic and diluted):
As reported $ (0.03) $ (0.01)
Pro Forma $ (0.04) $ (0.01)
Warrants
During the three months ended September 30, 2005, we issued revocable warrants
to purchase 200,000 shares of our common stock, cancelled warrants to purchase
2,066 shares of our common stock and honored the exercise of warrants for 2,934
shares of our common stock, as described below:
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 of
actually issuing the warrants.
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 three months ended September 30, 2005, 5,000 warrants were exercised,
resulting in the issuance of 2,934 shares of our common stock. The remaining
2,066 warrants were cancelled as part of a cashless exercise of the subject
warrants.
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 September 30, 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 three months ended September 30, 2005, $1,444 was expensed to
reflect the changes in the market value of the Put from June 30, 2005
to September 30, 2005.
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.
For the three months ended September 30, 2005, $45,000 was expensed and paid to
CMCP. During the three months ended September 30, 2004, we expensed $45,000 in
monthly retainers to CMCP. At September 30, 2004, amounts due and owing to CMCP
totaled $105,000 under the agreement. Also during this period, we charged
$27,500 to stockholders' equity as a reduction of the proceeds from common stock
sales placed by Chadbourn Securities and Laird Q. Cagan, and issued warrants to
purchase up to a total of 17,700 shares of common stock to CMCP, Chadbourn
Securities and Laird Q. Cagan in connection with the placement of our common
shares. These warrants were issued with a $1.50 exercise price and a seven year
term.
On August 10, 2004, Mr. Cagan loaned us $475,000 as a partial bridge financing
for our first acquisition in the Tullos Field Area. This loan was paid off in
full, including interest, in February 2005.
Eric McAfee, 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
$130,000 to Verdisys (Blast Energy) during 2003 and $25,960 during 2004 for
horizontal drilling services.
John Pimentel, a member of our Board of Directors, is associated with CMCP.
9. Liquidity and Capital Resources
At September 30, 2005, we had $1,727,437 of unrestricted cash and positive
working capital of $1,815,992, as compared to $2,548,688 of unrestricted cash
and positive working capital of $2,599,232 at June 30, 2005, and $50,832 of
unrestricted cash and negative working capital of $872,492 at September 30,
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.
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. We
believe 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 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 drilling program has commenced, we can give no
assurance that the assumptions in the reserve report will be achieved or that
the development program will be completed 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.
10. Subsequent Events
On October 19, 2005 we filed Amendment No. 1 to our Form SB-2 originally filed
with Securities and Exchange Commission ("SEC") on June 6, 2005. The amendment
was primarily made to include audited financial statements for our fiscal year
ended June 30, 2005, as requested by the SEC in their initial review. 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. Pursuant to a registration rights agreement, we have incurred a
penalty of $60,000 payable to the Rubicon Fund, representing 1% of gross
proceeds from the offering, payable for any month for which the registration
statement is not effective, beginning October 6, 2005. Notwithstanding the
foregoing, penalties accrue until Rubicon's shares become tradable under Rule
144, but in no event can the penalty cumulatively exceed 8% or $240,000. This
liability has been previously accrued for on our balance sheet, but is unpaid as
of this filing.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This Form 10-QSB and the information referenced herein contain statements that
constitute "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
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
The following table sets forth certain financial information with respect to our
oil and gas operations.
Three Months Ended
September 30
---------------------
Net to NGS 2005 2004 Variance % change
--------- --------- --------- ---------
Sales Volumes (net):
Oil (Bbl) 9,002 3,955 5,047 128%
Gas (Mcf) 9,838 11,252 (1,414) -13%
Oil and Gas (Boe) 10,642 5,830 4,812 83%
Revenue data (a):
Oil revenue $ 486,395 $ 164,523 $ 321,872 196%
Gas revenue 56,489 66,644 (10,155) -15%
--------- --------- ---------
Total oil and gas revenues $ 542,884 $ 231,167 $ 311,717 135%
Average prices (a):
Oil (per Bbl) $ 54.03 $ 41.60 $ 12.43 30%
Gas (per Mcf) 5.74 5.92 (0.18) -3%
Oil and Gas (per Boe) 51.01 39.65 11.37 29%
Expenses (per Boe)
Lease operating expenses and production taxes $ 43.62 $ 26.38 $ 17.24 65%
Depletion expense on oil and gas properties 7.13 6.88 0.25 4%
(a) Includes the cash settlement of hedging contracts
Net Income. For the three months ended September 30, 2005, we reported a net
loss of $800,059, or $0.03 loss per share on total revenues of $542,884, as
compared with a net loss of $302,636, or $0.01 loss per share on total revenues
of $231,167 for the three months ended September 30, 2004. The increase in
losses are attributable to increases in lease operating and general and
administrative expenses, partially offset by increases in revenues due to higher
sales and sales prices (see Lease Operating Expenses).
Sales Volumes. Oil sales volumes, net to our interest, for the three months
ended September 30, 2005 increased 128% to 9,002 Bbls, compared to 3,955 Bbls
for the three months ended September 30, 2004. The increase in sales volumes is
primarily due to an increase in oil production from our Tullos Field Area
acquisitions and the results of our recompletions in the Delhi Field.
Our net oil stock ending inventory increased 154% at September 30, 2005 to 4,079
Bbls, as compared to 1,609 Bbls at September 30, 2004, and increased 67%, or
1,638 Bbls, as compared to June 30, 2005. Increases in oil inventory are
attributable to the nature of our acquisitions in the Tullos Field Area, since
many of the Tullos Field leases do not make a full truckload within one month.
This causes erratic oil runs, due to the preference of our oil purchaser to
gather a full truckload from a single tank battery.
Net natural gas volumes sold for the three months ended September 30, 2005 were
9,838 Mcfs, a decrease of 13% from the three months ended September 30, 2004.
Gas volumes declined due to mechanical problems with our largest gas producer,
the Delhi Unit 184-2, resulting from severe plugging that occurred during a
workover in June 2005, gas gathering line leaks and normal production decline.
When compared to the three months ended June 30, 2005, natural gas sales are
down 6%, or 135 Mcfs, due primarily to the full quarter effect of the 184-2
mechanical problems.
Production. Net oil production for the three months ended September 30, 2005
increased 176% to 10,639 Bbls, compared to 3,850 Bbls for the three months ended
September 30, 2004. This is primarily due to the acquisition of wells in the
Tullos Field Area. Net natural gas production for the three months ended
September 30, 2005 declined 12% to 14,366 Mcfs, compared to 16,360 Mcfs for the
three months ended September 30, 2004. This was due to well downtime caused by
mechanical problems on our 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.
Oil and gas revenues increased 135% for the three month period ended September
30, 2005, compared to the same period in 2004, as a result of the two separate
acquisitions of producing leases in the Tullos Field Area. Another component of
the increase was a 29% increase in the sales prices we received per Boe during
the three months ended September 30, 2005 as compared to the three months ended
September 30, 2004.
Lease Operating Expenses. Lease operating expenses for the three months ended
September 30, 2005 increased $326,442 from the comparable 2004 period to
$464,190. The increase in operating expenses in 2005 is primarily attributable
to (1) an increase in the number of active wells due 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 $43.62 per
BOE did not meet our expectations for the three months ended September 30, 2005,
as compared to 2004's comparable quarter ($26.38), and as compared to the
previous three months ended June 30, 2005 ($24.39). The unfavorable variance in
the current quarter 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. At present, the 87-2
well appears to have stabilized. As previously reported, our Delhi 87-2 well is
over 50 years old. Following its recompletion earlier this 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.
Salaries, General and Administrative Expenses. Salaries, general and
administrative expenses (exclusive of non-cash stock compensation expense)
increased $206,361 to $471,204 for the three months ended September 30, 2005, as
compared to 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
$28,799 for the three months ended September 30, 2005 to $75,905 from $47,106
for the same period in 2004. The increase is due mostly to an 83% 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 September 30, 2005
increased $196,412 to $221,678, (of which $141,365 was cash expense) compared to
$25,266 (of which $12,082 was cash expense) for the three months ended September
30, 2004. The increase in interest expense was primarily due to interest expense
associated with the Prospect Facility, which was not outstanding in the
comparable 2004 quarter. Of the $221,678 of interest expense incurred in the
current three month period, $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 sporadic electricity outages.
Development Drilling Program. We originally scheduled our Delhi Field
development drilling program to begin in May 2005. The program consists of
drilling seven consecutive wells, all included in our proved undeveloped
reserves. Due to delays by the drilling contractor, we did not begin drilling
until the second week of October, 2005.
The first well drilled, the Delhi Unit 92-2, reached a total depth of slightly
more than 3,500 feet and encountered the objective pay sand we expected. The
92-2 has been completed and began delivering gas into our sales line on November
10, 2005. As of November 12, 2005, our second development well, the Delhi Unit
70-4, had been drilled, logged and production casing had been set.
The drilling rig will be retained in the field until the drilling program is
completed.
Liquidity and Capital Resources
At September 30, 2005, we had $1,727,437 of unrestricted cash and positive
working capital of $1,815,992, as compared to $2,548,688 of unrestricted cash
and positive working capital of $2,599,232 at June 30, 2005, and $50,832 of
unrestricted cash and negative working capital of $872,492 at September 30,
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.
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. We believe 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 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 drilling program has commenced, we can give
no assurance that the assumptions in the reserve report will be achieved or that
the development program will be completed 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.
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 end of our second fiscal
quarter.
Cash used in operating activities for the three months ended September 30, 2005
was $553,776 and cash used in operations for the comparative period in 2004 was
$164,321. 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 three months ended September 30, 2005
and 2004 was $260,952 and $805,523, respectively. Development capital
expenditures spent for the three months ended September 2005 was $260,301. For
the three months ended September 2004, we expended approximately $725,000 in
capital acquisition costs for the purchase of producing properties in our Tullos
Field Area, and approximately $80,000 was used for development capital at our
Delhi Field.
Cash used in financing activities for the three months ended September 30, 2005
was $6,523, applied primarily to the remaining balance of the Cananwill
insurance loan. In the comparable 2004 period, $652,845 of cash was provided
from financing activities, consisting of $481,597 in net proceeds from loans and
$554,723 of gross cash proceeds from the private sale of 369,200 shares of our
common stock, before commissions, less $350,716 used for loan repayments.
Budgeted Capital Expenditures. Our Delhi development drilling program began in
early October, 2005. Capital expenditures necessary to complete the drilling and
completion of seven proved undeveloped reserve locations is expected to be
approximately $1.3 million, assuming all wells scheduled to be drilled will also
be completed. We plan on funding this program out of working capital. As of
November 9, 2005, we have drilled and completed one well and drilled and logged
one other well. Five more wells are scheduled to be drilled during calendar year
2005.
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.
PART II - OTHER INFORMATION
ITEMS 1, 2, 3, 4 AND 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
A. Exhibits
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.
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: November 14, 2005 By: /s/ STERLING H. MCDONALD
-------------------------------
Sterling H. McDonald
Chief Financial Officer
Principal Financial and Accounting Officer