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 March 31, 2006
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)
(713) 935-0122
(Registrant's telephone number, including area code)
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 May 8, 2006, was 25,211,716.
Transitional Small Business Disclosure Format (Check one): Yes: __ No: X
NATURAL GAS SYSTEMS, INC.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets: March 31, 2006 (unaudited) and June 30, 2005 3
Consolidated Statements of Operations (unaudited): For the three and nine months
ended March 31, 2006 and 2005 4
Consolidated Statements of Cash Flows (unaudited): For the nine months ended
March 31, 2006 and 2005 5
Notes to Consolidated Financial Statements (unaudited) 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 12
ITEM 3. CONTROLS AND PROCEDURES 17
PART II. OTHER INFORMATION
ITEM 1. LITIGATION 18
SIGNATURES 19
PART I - FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, June 30,
2006 2005
------------ ------------
Assets (unaudited)
Current Assets:
Cash $ 207,831 $ 2,548,688
Accounts receivable, trade 266,230 300,761
Inventories (materials & supplies) 348,225 222,470
Prepaid expenses 114,828 84,304
Retainers and deposits 56,335 56,335
------------ ------------
Total current assets 993,449 3,212,558
Oil & Gas properties - full cost 8,358,670 5,276,303
Oil & Gas properties - not amortized 63,059 61,887
Less: accumulated depletion (633,985) (313,391)
------------ ------------
Net oil & gas properties 7,787,744 5,024,799
Furniture, fixtures, and equipment, at cost 15,117 12,113
Less: accumulated depreciation (6,854) (3,401)
------------ ------------
Net furniture, fixtures, and equipment 8,263 8,712
Restricted deposits 686,704 863,089
Other assets, net 317,987 356,066
------------ ------------
Total assets $ 9,794,147
$ 9,465,224
============ ============
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable $ 565,975 $ 240,389
Accrued liabilities 171,092 276,470
Notes payable, net of discount 4,062,946 6,754
Royalties payable 101,579 89,713
------------ ------------
Total current liabilities 4,901,592 613,326
Long term Liabilities:
Notes payable 0 4,000,000
Discount on notes payable 0 (1,093,452)
Asset retirement obligations 454,641 433,250
------------ ------------
Total liabilities 5,356,233 3,953,124
Stockholders' Equity:
Common Stock, par value $0.001 per share; 100,000,000 shares
authorized, 25,210,678 and 24,774,606 shares issued and
outstanding as of March 31, 2006 and June 30, 2005, respectively 25,210 24,774
Additional paid-in-capital 10,117,926 9,611,767
Deferred stock based compensation (225,989) (595,283)
Accumulated deficit (5,479,233) (3,529,158)
------------ ------------
Total stockholders' equity 4,437,914 5,512,100
------------ ------------
Total liabilities and stockholders' equity $ 9,794,147 $ 9,465,224
============ ============
See accompanying notes to condensed consolidated financial statements.
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
Three Months Ended Nine Months Ended
March 31, March 31,
2006 2005 2006 2005
------------ ------------ ------------ ------------
Revenues:
Oil sales $ 801,036 $ 308,171 $ 1,844,870 $ 723,625
Gas sales 83,730 111,722 420,618 293,203
Price risk management activities (6,164) (40,946) (13,066) (40,946)
------------ ------------ ------------ ------------
Total revenues 878,602 378,947 2,252,422 975,882
Expenses:
Lease operating costs 506,093 220,849 1,368,967 555,418
Production taxes 40,936 16,278 76,956 44,773
Depreciation, depletion and amortization 132,366 59,610 324,047 158,123
General and administrative 593,271 855,940 1,839,655 1,706,871
------------ ------------ ------------ ------------
Total operating expenses 1,272,666 1,152,677 3,609,625 2,465,185
------------ ------------ ------------ ------------
Loss from operations (394,064) (773,730) (1,357,203) (1,489,303)
Other revenues and expenses:
Interest income 7,626 2,128 41,517 8,226
Interest expense (221,694) (135,330) (634,388) (201,698)
------------ ------------ ------------ ------------
Total other revenues and expenses (214,068) (133,202) (592,871) (193,472)
------------ ------------ ------------ ------------
Net loss $ (608,132) $ (906,932) $ (1,950,074) $ (1,682,775)
============ ============ ============ ============
Loss per common share, basic and diluted $ (0.02) $ (0.04) $ (0.08) $ (0.07)
Weighted average number of common shares,
basic and diluted 25,309,557 23,397,156 24,864,403 23,299,719
See accompanying notes to condensed consolidated financial statements.
NATURAL GAS SYSTEMS, INC.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(unaudited)
Nine Months Nine Months
Ended March 31, Ended March 31,
2006 2005
----------- -----------
Cash flow from operating activities:
Net loss $(1,950,074) $(1,682,775)
Adjustments to reconcile net loss to net cash used by Operating
activities:
Stock-based compensation 381,385 620,589
Depletion 320,594 156,821
Depreciation 3,453 1,302
Accretion of asset retirement obligation 21,391 9,932
Amortization of deferred financing costs 43,016 0
Accretion of debt discount 113,648 0
Other non-cash items 34,727 0
Non cash penalty expense 240,000 0
Changes in assets and liabilities:
Accounts receivable 33,098 (152,001)
Retainers and deposits 0 (29,530)
Inventories (125,755) (134,191)
Accounts payable 325,586 360,018
Royalties payable 11,866 48,837
Prepaid expenses (30,524) 13,195
Accrued liabilities (55,378) 48,119
----------- -----------
Net cash used by operating activities (632,967) (739,684)
Cash flow from investing activities:
Capital expenditures for oil and gas properties (3,082,106) (1,836,876)
Capital expenditures for furniture, fixtures and equipment (3,004) (5,037)
Restricted deposits 176,385 0
Other assets, net 17,716 (344,811)
----------- -----------
Net cash used in investing activities (2,891,009) (2,186,724)
Cash flow from financing activities:
Deferred financing costs (22,654) (259,705)
Proceeds from notes payable 1,040,764 3,855,721
Payments on notes payable (6,754) (1,737,336)
Equity and transaction costs 171,763 1,678,307
----------- -----------
Net cash provided by financing activities 1,183,119 3,536,987
----------- -----------
Net increase (decrease) in cash (2,340,857) 610,579
Cash and cash equivalents, beginning of period 2,548,688 367,831
----------- -----------
Cash and cash equivalents, end of period $ 207,831 $ 978,410
=========== ===========
Supplemental disclosure of cash flow information:
Interest paid $ 443,229 $ 168,475
Non cash equity adjustment $ 50,000 $ 0
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 March 31, 2006, 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 interim periods are not
necessarily indicative of results to be expected for a full 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. Upon adoption of SFAS 123R on July 1, 2006, we currently estimate that
our stock based compensation cost will increase by a material amount. Due to the
non-cash nature of this charge, adoption of SFAS 123R will have no impact on our
financial or cash position.
3. Acquisition
On January 31, 2006, we acquired from an unrelated third party, an additional
net revenue interest in one of our existing fields. Funding of the $1.0 million
purchase price was provided by an additional $1.0 million advance under our
Prospect Facility, thereby increasing the maturity value of our note due them at
maturity to $5.0 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.
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.
The following table sets forth the computation of basic and diluted earnings
(loss) per share:
Three Months Ended
March 31
----------------------------------
2006 2005
------------------ ------------
Numerator:
Net loss applicable to common stockholders $ (608,132) $ (906,932)
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 $ (608,132) $ (906,932)
================== ============
Denominator: 25,039,557 23,397,156
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 25,039,557 23,397,156
================== ============
Loss per common share:
Basic and diluted $ (0.02) $ (0.04)
================== ============
Nine Months Ended
March 31
-------------------------------
2006 2005
--------------- ------------
Numerator:
Net loss applicable to common stockholders $ (1,950,074) $ (1,682,775)
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 $ (1,950,074) $ (1,682,775)
=============== ============
Denominator: 24,864,403 23,299,719
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 24,864,403 23,299,719
=============== ============
Loss per common share:
Basic and diluted $ (0.08) $ (0.07)
=============== ============
5. Debt
On March 3, 2006, the Company entered into a subordinated loan agreement with
Laird Q. Cagan whereby Mr. Cagan loaned the Company $250,000 (the "Subordinated
Note"). The Subordinated Note has a one year term and accrues interest at 10%,
payable at maturity. The Subordinated Note also has certain acceleration
provisions in the event the Company raises additional capital in excess of $2
million and is subject and subordinated to the Company's previous senior secured
loan agreement with Prospect Energy Corporation, dated February 3, 2005, as
amended, totaling $5,000,000. The proceeds of the Subordinated Loan are intended
for general working capital purposes. As reported in footnote 9 Related Party
Transactions, Laird Q. Cagan, our Company's Chairman of the Board, also acts as
the Company's non-exclusive placement agent for capital raising services through
Chadbourn Securities, Inc.
On February 3, 2005 we closed a financing agreement with Prospect Energy
Corporation (the "Prospect Facility" or "Facility") and ultimately borrowed
$4,000,000 in 2005, secured by all of our assets. On January 31, 2006, NGS
borrowed an additional $1,000,000 under the terms of the First Amendment to the
Loan Agreement with Prospect Energy Corporation to fund the purchase of a net
revenue interest in producing oil and gas properties located in Louisiana. At
maturity, or exclusive of any prepayment penalty on early prepayment, the total
amount owed under the Facility will be $5,000,000.
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).
Through the immediately prior testing date of January 31, 2006, we were in
compliance with all of our covenants, including our obligation to maintain an
Earnings Before Interest (cash basis), Taxes, Depreciation and Amortization
("EBITDA") to interest payable coverage ratio of 2.0:1 over a three month
measurement period under the Prospect Facility (the "Interest Coverage Ratio").
The Interest Coverage Ratio is required to be tested at the end of each calendar
quarter, failing which, a default does not occur if we show compliance for the
three months ended one month after the calendar quarter. For the three months
ending December 31, 2005, we did not meet the calendar quarter test, but did
show compliance for the three months ended January 31, 2006.
As previously reported, we have relied on the expected results of our 2005
Development Drilling Program to improve our Interest Coverage Ratio to the point
of compliance, based on W. D. Von Gonten's report of proved undeveloped reserves
that comprised four out of the five drilling locations we completed. Although
our 2005 Development Drilling Program assisted us in meeting the Interest
Coverage Ratio at January 31, 2006, subsequent production results did not yield
sufficient EBITDA to comply with the Interest Coverage Ratio for the three
months ended March 31, 2006.
As a result of our recent operating results and the additional EBITDA required
to cover additional interest expense arising from our $1,000,000 debt drawdown
on January 31, 2006 to purchase a net revenue interest in one of our fields, we
have been in discussions with Prospect regarding the status of the loan, and the
possibility of obtaining temporary relief from the interest coverage covenant
and the covenant to fund an additional $350,000 to the debt service reserve
account if the loan remained outstanding. On May 16, 2006, we notified Prospect
that the Interest Coverage Ratio for the three months ended April 30, 2006 had
not yet been determined, but that the ratio would be less than the 2.0:1
requirement under the loan agreement and accordingly, an event of default on the
loan had occurred. After the close of business on May 16, Prospect notified us
by email that they had waived all defaults and Events of Default until further
notice. As we did not receive a formal and complete waiver from Prospect, the
Prospect Loan and the associated Discount on Note Payable were reclassified as
current amounts. We have sufficient funds available to fully repay the principal
balance of the loan and the accrued interest thereon. If repaid, we may be
required to raise a similar amount of new capital if the pending Delhi sale is
not completed due to Buyer's objection by May 22, 2006 as to major title or
environmental defects or casualty loss exceeding $2.5 million each.
On May 19, 2006, we provided the required notice of repayment to Prospect to pay
off all amounts due on the loan, including the principal amount due of $5
million and accrued interest.
6. Contingent Liabilities
On November 17, 2005, a multi-plaintiff 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.
During the three months ended March, 2006, we filed our response and Motion to
Stay Proceedings and Dilatory and Declinatory Exceptions with respect to this
proceeding.
7. 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"). We plan to adopt SFAS 123R effective July 1, 2006.
Options
In February 2006, the Board of Directors: (i) granted stock options to purchase
150,000 shares of common stock (of which 100,000 shares are vested immediately
as a bonus for the prior year) 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
four year vesting schedule, to Sterling H. McDonald, our Chief Financial
Officer, (ii) granted a non-qualified stock option to purchase 50,000 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 six month vesting
schedule, to Steven D. Lee, legal counsel to the company, and (iii) accelerated
the vesting of previously granted, but unvested non-qualified stock options to
Steven D. Lee, resulting in accelerated non-cash stock compensation expense of
approximately $8,300 each month for the next six months. With respect to (ii)
above, the fair value of the options is $39,275, which will be amortized over a
six month period beginning March 2006. The following assumptions were used in
the Black-Scholes options pricing model: term = 1 year; volatility = 150%,
discount rate = 4.50%.
All stock options mentioned above were granted under the 2004 Stock Plan.
Warrants
In January 2006, pursuant to the terms of the Additional Advance under the First
Amendment to the Prospect Facility, the Company was required to issue to
Prospect Energy Corporation five-year warrants to purchase up to 150,000 shares
of NGS common stock at an exercise price of $1.4495 per share, and "revocable
warrants" to purchase up to an additional 100,000 shares of common stock at an
exercise price of $1.4495 per share. The revocable warrants are subject to
cancellation by the Company prior to their exercise if the Company meets and
maintains certain operating cash flow targets. Using the Black-Scholes options
pricing model to compute fair value of the warrants, $209,236 was calculated and
recorded to equity and as an increase to the discount on the Prospect Facility.
The following assumptions were used in the calculation: term = 2 years,
volatility = 150%, discount rate = 4.52%, and a 60% probability that the
revocable warrants will be revoked.
In February 2006, the Board of Directors approved the following: (i) granted
irrevocable warrants to purchase 150,000 shares (100% vested immediately for Mr.
Herlin as a bonus for the prior year) and 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 a four year vesting schedule to Robert
S. Herlin, our President and Chief Executive Officer and Sterling H. McDonald,
our Chief Financial Officer, respectively, and (ii) granted revocable warrants
to purchase 250,000 and 50,000 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 a four year vesting schedule to Mr. Herlin and Mr.
McDonald, respectively. For the fair market value calculation, the following
assumptions were used in the Black-Scholes options pricing model: term = 4
years, volatility = 150% and discount rate = 4.50%.
At February 1, 2006, we did not meet the tests to revoke 400,000 warrants issued
to Prospect Energy Corporation under our original February 2005 agreement with
them. Consequently, these warrants are now fully exercisable, at $0.75 per
share, at any time through February 2, 2010.
The following tables illustrate the effect on net loss and loss per share for
the three and nine months ended March 31, 2006 and 2005, 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
March 31
--------------------------
2006 2005
----------- -----------
Pro forma impact of Fair Value Method (SFAS 148):
Net loss attributable to common stockholders, as reported $ (608,132) $ (906,932)
Plus compensation expense determined under Intrinsic Value Method (APB 25) 27,328 828
(Less) compensation expense determined under Fair Value Method (567,826) (56,516)
----------- -----------
Pro forma net loss attributable to common stockholders $(1,148,630) $ (962,620)
Loss per share (basic and diluted):
As reported $ (0.02) $ (0.04)
Pro Forma $ (0.05) $ (0.04)
Nine Months Ended
March 31
--------------------------
2006 2005
----------- -----------
Pro forma impact of Fair Value Method (SFAS 148):
Net loss attributable to common stockholders, as reported $(1,950,074) $(1,682,775)
Plus compensation expense determined under Intrinsic Value Method (APB 25) 144,208 92,984
(Less) compensation expense determined under Fair Value Method (1,196,257) (135,508)
----------- -----------
Pro forma net loss attributable to common stockholders $(3,002,123) $(1,725,299)
Loss per share (basic and diluted):
As reported $ (0.08) $ (0.07)
Pro Forma $ (0.12) $ (0.07)
8. 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 March 31, 2006, 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. Lastly, on January 27, 2006 we extended
our crude oil 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 90 Bbls of oil
per day, in exchange for a fixed price of $69.30 per Bbl, plus or
minus NYMEX to posted field price basis risk.
(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 nine months ended March 31, 2006, $13,066 was expensed to
reflect the changes in the market value of the Put from June 30,
2005 to March 31, 2006.
9. 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
$5,000. 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. On February
13, 2006, Chadbourn and the Company entered into a revised agreement that
provides for a reduced level of cash fee for equity raises, beginning at 8% and
declining to 4% subject to the amount of equity raised, and a fixed 4% warrant
fee.
On March 3, 2006, the Company entered into a subordinated loan agreement with
Laird Q. Cagan whereby Mr. Cagan loaned the Company $250,000 (the "Subordinated
Note"). The Subordinated Note has a one year term and accrues interest at 10%,
payable at maturity. See also footnote 5 Debt.
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.
10. 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 March 31, 2006 is as follows:
Asset retirement obligation at June 30, 2005 $433,250
Liabilities incurred --
Liabilities settled --
Accretion expense 21,391
--------
Asset retirement obligation at March 31, 2006 $454,641
11. Equity
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 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. We accounted for the issuance of the 160,000 additional shares, in
accordance with FAS 123, by recording $240,000 of fair value expense and
crediting additional paid-in-capital.
On or about January 15, 2006, we issued 262,314 shares of common stock upon the
exercise of a warrant agreement dated January 1, 2005 between the company and
Tatum CFO Partners, LLP.
On March 20, 2006 we filed Amendment No. 4 to our Form SB-2 originally filed
with Securities and Exchange Commission ("SEC") on June 6, 2005, and amended on
October 19, 2005, January 24, 2006, and March 3, 2006, respectively. The SEC has
reviewed the amended registration statement and on March 22, 2006, declared the
registration statement effective.
12. Liquidity and Capital Resources
At March 31, 2006, we had $207,831 of unrestricted cash and negative working
capital of $3,908,143, as compared to $433,465 of unrestricted cash and positive
working capital of $619,025 at December 31, 2005, and $2,548,688 of unrestricted
cash and positive working capital of $2,599,232 at June 30, 2005. During the
three months ended March 31, 2006, we continued to consume working capital to
fund the completion of our 2005 Development Drilling Program.
Our negative working capital at March 31, 2006, was mostly due to our
transferring the Prospect loan from a long term liability to a short term
liability because we were out of compliance with our loan covenants as described
in Note 5 "Debt". At May 16, 2006 we had sufficient cash resources, mostly from
the $5 million down-payment we received from the pending sale of our Delhi Unit,
to repay the principal amount of the Prospect loan. See Notes 5 "Debt" and 13
"Subsequent Events" for a detailed discussion of our liquidity.
13. Subsequent Events
On May 8, 2006, one of our subsidiaries entered into a definitive agreement with
Denbury Resources, Inc. (NYSE:DNR) to conduct an enhanced oil recovery project
in the Delhi Holt Bryant Unit within the Delhi Field in northeast Louisiana (the
"Delhi Unit"). NGS will contribute its working interest in the Delhi Unit and
Denbury will contribute all development capital, technical expertise and
required amounts of proven reserves of carbon dioxide ("CO2") that will be
injected into the oil reservoirs.
The principal terms of the agreement call for NGS to receive $5 million as a
down payment and an additional $45 million at closing, subject to adjustments,
if any, following normal due diligence inspections. NGS will deliver to Denbury
an initial 100% working interest and 80% net revenue interest in the Delhi Unit,
while retaining a separate 4.8% royalty interest within the Delhi Unit and a 25%
working interest in other depths. After the project generates $200 million of
net cash flows before capital expenditures, NGS will regain a 25% working
interest (20% net revenue interest) in the Delhi Unit. Denbury has estimated
that its capital expenditures in the overall project will likely reach or exceed
$200 million. Closing of this transaction is scheduled for June 1, 2006.
On May 22, 2006, Denbury submitted their schedule of environmental and title
defects pursuant to the terms of our mutually executed purchase and sale
agreement for the Delhi Unit, the sum of each being less than the threshold
required for elective termination by Denbury. Consequently, failing a major
casualty loss by June 1, 2006, either the pending sale of Delhi Unit will be
completed or we will earn the $5 million deposit as liquidated damages from any
elective termination by Denbury.
On May 19, 2006, we provided the required notice of repayment to Prospect to pay
off all amounts due on the loan, including the principal amount due of $5
million and accrued interest.
On May 16, 2006, NGS, Inc. initiated a Common Stock private placement of up to
450,000 shares of its common stock, par value, $0.001 per share, at a price of
$2.25 per share. As of May 19, 2006, we have received gross proceeds of $750,000
pursuant to executed subscription agreements. Our placement agent, Chadbourn
Securities, Inc, shall receive total fees not exceeding 8% of the first
$1,000,000 and 7% of the balance of the proceeds raised in this Offering plus
total warrants not exceeding 4% of the shares of common stock purchased in this
Offering, in each case with respect to sales in states in which it is registered
as a broker dealer, exercisable at the Offering price. Laird Cagan, the Chairman
of our Board of Directors and a significant shareholder, is acting as a
registered representative of Chadbourn in this offering and will be receiving a
portion of the fees paid to Chadbourn.
On May 5, 2006, the Board of Directors approved a recommendation by the
Compensation Committee, following approval by the Compensation Committee on May
4, 2006, to award a total of 200,000 incentive stock options to three employees,
excluding Robert Herlin, President, and Sterling McDonald, CFO, vesting over
four years, and exercisable at a fixed price equal to the closing price at the
time of the grant. On May 10, 2006, the Board of Directors awarded 50,000 stock
options to each of E.J. DiPaolo and Gene Stoever, and 25,000 stock options to
William Dozier, vesting over two years, exercisable at a fixed price equal to
the closing price at the time of the grant. The three recipients are independent
directors on the Board of Directors.
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.
Update to subsequent events from prior quarter
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 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 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 March 20, 2006 we filed Amendment No. 4 to our Form SB-2 originally filed
with Securities and Exchange Commission ("SEC") on June 6, 2005, and amended on
October 19, 2005, January 24, 2006, and March 3, 2006, respectively. The SEC has
reviewed the amended registration statement and on March 22, 2006, declared the
registration statement effective.
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 months ended
March 31, 2006, our sales volumes and revenues increased by 74% and 132%,
respectively, over the prior year three month period. For the nine months ended
March 31, 2006, our sales volumes and revenues increased by 85% and 131%,
respectively, over the prior year nine month period. After accounting for lease
operating expense and production taxes, field income before depletion expense
increased 134% and 115% for the three and nine months ended March 31, 2006,
respectively, while general and administrative expenses declined 31% and rose
8%, respectively for the same periods. Losses from Operations declined 49% and
9% for the comparable three and nine month periods.
The drilling results of the 2005 Delhi Development Drilling Program have not
produced the immediate favorable results we expected. From a technical
perspective, we generally found the targeted reservoirs "up-dip" of previously
watered-out zones at the structural level and thickness predicted.
Unfortunately, it appears that the reservoirs we targeted became less permeable
toward the truncation point, or updip limit, thereby resulting in far less
production than anticipated. At this time, we believe that artificial
stimulation of the reservoirs, or hydraulic fracturing, may result in improved
production rates. Such stimulations will require further expenditures and
contain an element of risk as to success. Furthermore, the problems encountered
in drilling and completing the wells due to the changed reservoir quality and
quality of the vendor services received led to far higher capital expenditures
than budgeted. The drilling results have affected our liquidity and capital
resources, as more fully explained in the Liquidity and Capital Resources
section discussed below.
Conversely, on May 8, 2006, one of our subsidiaries entered into a definitive
agreement with Denbury Resources, Inc. (NYSE:DNR) to conduct an enhanced oil
recovery project in the Delhi Holt Bryant Unit within the Delhi Field in
northeast Louisiana (the "Delhi Unit"). NGS will contribute its working interest
in the Delhi Unit and Denbury will contribute all development capital, technical
expertise and required amounts of proven reserves of carbon dioxide ("CO2") that
will be injected into the oil reservoirs. This enhanced oil recovery (EOR)
project targets tertiary recovery of significant un-produced petroleum resources
that are believed to remain after the primary and secondary water flood
operations that have been conducted in the Delhi Unit across a 50 year span.
The principal terms of the agreement call for NGS to receive $5 million as a
down payment and an additional $45 million at closing, subject to adjustments,
if any, following normal due diligence inspections. NGS will deliver to Denbury
an initial 100% working interest and 80% net revenue interest in the Delhi Unit,
while retaining a separate 4.8% royalty interest within the Delhi Unit and a 25%
working interest in other depths. After the project generates $200 million of
net cash flows before capital expenditures, NGS will regain a 25% working
interest (20% net revenue interest) in the Delhi Unit.
Denbury has estimated that its capital expenditures in the overall project will
likely reach or exceed $200 million. NGS will bear no portion of the project
capital expenditures until its reversionary interest reverts. Closing is
scheduled for June 1, 2006 following repayment of the Prospect facility on or
before the closing date.
Management views this transaction as a substantial addition to shareholder
value, consistent with our charter to acquire mature petroleum resources for the
purpose of creating value through the use of technology and capital for the
extraction of remaining known resources. We look forward to redeploying the cash
raised from this transaction into other projects that are consistent with this
charter.
Three months ended March 31, 2006 compared to three months ended March 31, 2005
The following table sets forth certain financial information with respect to our
oil and gas operations.
Three Months Ended
March 31
---------------------
Net to NGS 2006 2005 Variance % change
--------- --------- --------- ---------
Sales Volumes:
Oil (Bbl) 14,496 6,545 7,951 121%
Gas (Mcf) 10,003 16,378 (6,375) -39%
Oil and Gas (Boe) 16,163 9,275 6,888 74%
Revenue data (a):
Oil revenue $ 794,872 $ 267,225 $ 527,647 197%
Gas revenue 83,730 111,722 (27,992) -25%
--------- --------- ---------
Total oil and gas revenues $ 878,602 $ 378,947 $ 499,655 132%
Average prices (a):
Oil (per Bbl) $ 54.83 $ 40.83 $ 14.00 34%
Gas (per Mcf) 8.37 6.82 1.55 23%
Oil and Gas (per Boe) 54.36 40.86 13.50 33%
Expenses (per Boe)
Lease operating expenses and production taxes $ 33.84 $ 25.93 $ 7.91 31%
Depletion expense on oil and gas properties 8.12 6.01 2.11 35%
(a) Includes the cash settlement of hedging contracts
Net Loss. For the three months ended March 31, 2006, we reported a net loss of
$608,132 or $0.02 loss per share on total revenues of $878,602, as compared to a
net loss of $906,936 or $0.04 loss per share on total revenues of $378,947 for
the three months ended March 31, 2005. The decrease in loss is attributable
primarily to higher revenues due to increased production and sales volumes,
higher commodity prices, lower general and administrative expenses, offset by
unfavorable nonrecurring lease operating costs.
Sales Volumes. Oil sales volumes, net to our interest, for the three months
ended March 31, 2006 increased 121% to 14,496 Bbls, compared to 6,545 Bbls for
the three months ended March 31, 2005. The increase in sales volumes is
primarily due to oil sales from the Chadco acquisition in the Tullos Field Area
and the result of workovers, recompletions and the development drilling program
at Delhi field.
Net natural gas volumes sold for the three months ended March 31, 2006 were
10,003 Mcfs, a decrease of 39% from the three months ended March 31, 2005. The
normal decline rate is primarily attributable for this decrease, slightly offset
by the new Delhi 92-2 well which was drilled and completed in early November.
Production. Oil production varies from oil sales volumes by changes in crude oil
inventories, which are not carried on the balance sheet. Net oil production for
the three months ended March 31, 2006 increased 97% to 13,890 Bbls, compared to
7,046 Bbls for the three months ended March 31, 2005. This is primarily due to
the acquisition of additional wells in the Tullos Field Area and results of
development drilling and other work in the Delhi Field. Net natural gas
production for the three months ended March 31, 2006 decreased 54% to 10,147
Mcfs, compared to 21,846 Mcfs for the three months ended March 31, 2005, due to
depletion in all gas wells at Delhi field.
Oil and Gas Revenues. Revenues presented in the table above and discussed herein
represent revenue from sales of our oil and natural gas production volumes, net
to our interest. Production sold under fixed price delivery contracts, which
have been designated for the normal purchase and sale exemption under SFAS 133,
are also included in these amounts. Realized prices may differ from market
prices in effect during the periods, depending on when the fixed delivery
contract was executed.
Oil and gas revenues increased 132% for the three month period ended March 31,
2006, compared to the same period in 2005, as a result of increases in sales
volumes due primarily to the Chadco acquisition of producing leases in the
Tullos Field Area and the Delhi Development drilling program. Another component
of the revenue increase is a 33% increase in the sales prices received per BOE
during the three months ended March 31, 2006 as compared to the three months
ended March 31, 2005.
Lease Operating Expenses. Lease operating expenses for the three months ended
March 31, 2006 increased $306,551 from the comparable 2005 period to $547,029.
The increase in operating expenses in 2006 is primarily attributable to (1) an
increase in the number of active wells due to the acquisition of producing
properties in the Tullos Field Area; (2) substantial increases in overall
industry service costs and (3) nonrecurring lease cleanup costs.
General and Administrative Expenses. General and administrative expenses were
$593,271for the three months ended March 31, 2006, a decrease of $262,669 from
$855,940 for the three months ended March 31, 2005. Non-cash stock compensation
expense decreased approximately $400,000 from the prior comparative quarter,
offset by higher overall general and administrative expenses in the current
quarter due to significant expenses associated with a being a public registrant,
including expenses for audited financial statements, SEC counsel, outside
engineering estimates, D&O insurance, outside director fees and other related
costs.
Depletion and Amortization Expense. Depletion and amortization expense increased
$75,516 for the three months ended March 31, 2006 to $131,246 from $55,730 for
the same period in 2005. The increase is primarily due to a 74% increase in
sales volumes and a 35% increase in the average depletion rate, period over
period.
Interest Expense. Interest expense for the three months ended March 31, 2006
increased $86,364 to $221,694 (of which $160,713 was cash expense) compared to
$135,330 (of which $70,762 was cash expense) for the three months ended March
31, 2005. The increase in interest expense was primarily due to interest expense
associated with the Prospect facility, which was only partially outstanding in
the comparable period.
Nine months ended March 31, 2006 compared to nine months ended March 31, 2005
Nine Months Ended
March 31
-----------------------
Net to NGS 2006 2005 Variance % change
---------- ---------- ---------- ----------
Sales Volumes:
Oil (Bbl) 35,277 15,747 19,530 124%
Gas (Mcf) 43,962 43,495 467 1%
Oil and Gas (Boe) 42,604 22,996 19,608 85%
Revenue data (a):
Oil revenue $1,831,804 682,679 $1,149,125 168%
Gas revenue 420,618 293,203 127,415 43%
---------- ---------- ----------
Total oil and gas revenues $2,252,422 $ 975,882 $1,276,540 131%
Average prices (a):
Oil (per Bbl) $ 51.93 $ 43.35 $ 8.58 20%
Gas (per Mcf) 9.57 6.74 2.83 42%
Oil and Gas (per Boe) 52.87 42.44 10.43 25%
Expenses (per Boe)
Lease operating expenses and production taxes $ 33.94 $ 26.10 $ 7.84 30%
Depletion expense on oil and gas properties 7.52 6.82 0.70 10%
(a) Includes the cash settlement of hedging contracts
Net Loss. For the nine months ended March 31, 2006, we reported a net loss of
$1,950,074 or $0.08 loss per share on total revenues of $2,252,422, as compared
with a net loss of $1,682,775 or $0.07 loss per share on total revenues of
$975,882 for the nine months ended March 31, 2005. The increase in loss is
attributable to overall increases in lease operating and general and
administrative expenses including nonrecurring lease operating costs, partially
offset by increases in revenues due to higher sales volumes and sales prices.
Excluding non-cash stock compensation expense of $381,385, our net loss for the
nine months ended March 31, 2006 was $1,568,689, or $0.06 loss per share. By
comparison, excluding non-cash stock compensation expense of $620,588 for the
nine months ended March 31, 2005, our net loss was $1,062,187, or $0.05 loss per
share.
Sales Volumes. Oil sales volumes, net to our interest, for the nine months ended
March 31, 2006 increased 124% to 35,277 Bbls, compared to 15,747 Bbls for the
nine months ended March 31, 2005. The increase in sales volumes is primarily due
to oil sales from the Chadco acquisition in the Tullos Field Area, the result of
workovers and recompletions in our portfolio and the results of the development
drilling program at Delhi field.
Net natural gas volumes sold for the nine months ended March 31, 2006 were
43,962 Mcfs, an increase of 1% from the nine months ended March 31, 2005. Normal
production declines were offset with new sales volumes from the Delhi 92-2 well
which was drilled and completed in late 2005.
Production. Oil production varies from oil sales volumes by changes in crude oil
inventories, which are not carried on the balance sheet. Net oil production for
the nine months ended March 31, 2006 increased 122% to 36,390 Bbls, compared to
16,421Bbls for the nine months ended March 31, 2005. This is primarily due to
the acquisition of wells in the Tullos Field Area, the result of workovers and
recompletions in our portfolio and the results of the development drilling
program at Delhi field.
Our net oil stock ending inventory decreased approximately 28% at March 31, 2006
to approximately 4,300 Bbls, as compared to approximately 6,000 Bbls at March
31, 2005. Decreases in oil inventory were attributable to coordinating with our
purchaser to pick up half loads at Tullos Field area since many of these leases
do not make a full truckload within one month (one truckload equals ~ 160 Bbls).
This has caused erratic oil runs from month to month.
Net natural gas production for the nine months ended March 31, 2006 decreased
10% to 53,716 Mcfs, compared to 59,367 Mcfs for the nine months ended March 31,
2005. Normal production declines were offset with new production from the Delhi
92-2 well which was drilled and completed in late 2005.
Oil and Gas Revenues. Revenues presented in the table above and discussed herein
represent revenue from sales of our oil and natural gas production volumes, net
to our interest. Production sold under fixed price delivery contracts, which
have been designated for the normal purchase and sale exemption under SFAS 133,
are also included in these amounts. Realized prices may differ from market
prices in effect during the periods, depending on when the fixed delivery
contract was executed.
Oil and gas revenues increased 131% for the nine month period ended March 31,
2006, compared to the same period in 2005, as a result of a 85% increase in
production volumes due to the Chadco and Atkins acquisitions of producing leases
in the Tullos Field Area and increases in production from our Delhi Field as a
result of the development drilling program. Another component of the increase
was a 25% increase in the average sales prices we received per BOE during the
nine months ended March 31, 2006 as compared to the nine months ended March 31,
2005.
Lease Operating Expenses. Lease operating expenses for the nine months ended
March 31, 2006 increased $845,732 from the comparable 2005 period to $1,445,923.
The increase in operating expenses for this nine period is primarily
attributable to (1) an increase in the number of active wells due to the
acquisition of properties in the Tullos Field Area, (2) substantial increases in
overall industry service costs, (3) high workover costs associated with our
Delhi 87-2 and 197-2 wells, repairs to our salt water disposal system and
repairs to two separate gas gathering line leaks, and (4) nonrecurring lease
cleanup costs.
On a BOE basis, lease operating expense and production taxes totaling $33.94 per
BOE did not meet our expectations for the nine months ended March 31, 2006, as
compared to the prior year's comparable period of $26.10. The unfavorable
variance in the current period was predominately due to the previously mentioned
workover costs associated with an unusually large number of our Delhi wells,
combined with the loss of production from well downtime while working over the
wells. Over half of this unfavorable variance was attributable to workover
expenses incurred to maintain production on our Delhi 87-2 well, which currently
accounts for the majority of our production from our Delhi Field. As previously
reported, our Delhi 87-2 well is over 50 years old.
General and Administrative Expenses. General and administrative expenses for the
nine months ended March 31, 2006 were $1,839,655, an increase of $132,784 as
compared to $1,706,871 for the comparable prior year period. The increase is
primarily due to an increase in employees from two to five and implementation of
an outsourced property accounting service with Petroleum Financial Incorporated.
Overall general and administrative expenses are high due to expenses associated
with a being a public registrant, including expenses for audited financial
statements, SEC counsel, outside engineering estimates, director & officer
insurance, outside director fees and other related costs; offset by a decrease
in non-cash stock compensation expense of approximately $239,000, from the
comparative period.
Depletion and Amortization Expense. Depletion and amortization expense increased
$163,773 for the nine months ended March 31, 2006 to $320,594 from $156,821 for
the same period in 2005. The increase is primarily due to an 85% increase in
sales volumes and a 10% increase in the average depletion rate, period over
period.
Interest Expense. Interest expense for the nine months ended March 31, 2006
increased $432,690 to $634,388 (of which $443,229 was cash expense) compared to
$201,698 (of which $168,475 was cash expense) for the nine months ended March
31, 2005. The increase in interest expense was primarily due to interest expense
associated with the Prospect facility, which was only partially outstanding in
the comparable period.
Liquidity and Capital Resources
At March 31, 2006, we had $207,831 of unrestricted cash and negative working
capital of $3,908,143, as compared to $2,548,688 of unrestricted cash and
positive working capital of $2,599,232 at June 30, 2005, and $978,410 of
unrestricted cash and positive working capital of $832,241 at March 31, 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.
As discussed more fully below, our negative working capital at March 31, 2006
was mostly due to our transferring the Prospect loan from a long term liability
to a short term liability. At May 16, 2006 we had sufficient cash resources,
mostly from the $5 million down-payment we received from the pending sale of our
Delhi Unit, to repay the principal amount of the Prospect loan.
On January 31, 2006, we borrowed an additional $1,000,000 under the terms of the
First Amendment to the Loan Agreement with Prospect Energy Corporation to fund
the purchase of a net revenue interest in producing oil and gas properties
located in Louisiana. At March 31, 2006, our book balance was $3,810,960, 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
$5,000,000.
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).
Through the immediately prior testing date of January 31, 2006, we were in
compliance with all of our covenants, including our obligation to maintain an
Earnings Before Interest (cash basis), Taxes, Depreciation and Amortization
("EBITDA") to interest payable coverage ratio of 2.0:1 over a three month
measurement period under the Prospect Facility (the "Interest Coverage Ratio").
The Interest Coverage Ratio is required to be tested at the end of each calendar
quarter, failing which, a default does not occur if we show compliance for the
three months ended one month after the calendar quarter. For the three months
ending December 31, 2005, we did not meet the calendar quarter test, but did
show compliance for the three months ended January 31, 2006.
As previously reported, we have relied on the expected results of our 2005
Development Drilling Program to improve our Interest Coverage Ratio to the point
of compliance, based on W. D. Von Gonten's report of proved undeveloped reserves
that comprised four out of the five drilling locations we completed. Although
our 2005 Development Drilling Program assisted us in meeting the Interest
Coverage Ratio at January 31, 2006, subsequent production results did not yield
sufficient EBITDA to comply with the Interest Coverage Ratio for the three
months ended March 31, 2006. Based on our most recent operating results and the
additional EBITDA required to cover additional interest expense arising from our
$1,000,000 debt drawdown on January 31, 2006 to purchase a net revenue interest
in one of our fields, we have been in discussions with Prospect regarding the
status of the loan, and the possibility of obtaining temporary relief from the
interest coverage covenant and the covenant to fund an additional $350,000 to
the debt service reserve account if the loan remained outstanding. On May 16,
2006, we notified Prospect that the Interest Coverage Ratio for the three months
ended April 30, 2006 had not yet been determined, but that the ratio would be
less than the 2.0:1 requirement under the loan agreement and accordingly, an
event of default on the loan had occurred.
After the close of business on May 16, 2006, Prospect notified us by email that
they had waived all defaults and Events of Default until further notice. As we
did not receive a formal and complete waiver from Prospect, the loan and
associated Discount for Note Payable were reclassified as current amounts. We
have sufficient funds available to fully repay the principal balance of the loan
and the accrued interest thereon. If repaid, we may be required to raise a
similar amount of new capital if the pending Delhi sale is not completed due to
Buyer's objection by May 22, 2006, concerning major title, environmental or
casualty losses exceeding $2.5 million each.
On May 22, 2006, Denbury submitted their schedule of environmental and title
defects pursuant to the terms of our mutually executed purchase and sale
agreement for Delhi Unit, the sums of each being less than the threshold
required for elective termination. Consequently, failing a major casualty loss
by June 1, 2006, either the pending sale of Delhi Unit will be completed or we
will earn the $5 million deposit as liquidated damages from any elective
termination.
On May 19, 2006, we provided the required notice of repayment to Prospect to pay
off all amounts due on the loan, including the principal amount due of $5
million and accrued interest.
Cash used in operating activities for the nine months ended March 31, 2006 was
$632,967 and cash used in operations for the comparative period was $739,684.
The decrease in cash used in operating activities was primarily due to lower net
cash losses from operations before changes in working capital, offset with
higher operating expenses resulting in higher operating losses.
Cash used in investing activities in the nine months ended March 31, 2006 and
2005 was $2,891,009 and $2,186,724, respectively. In 2006, the majority of the
development capital expenditures were spent on the 2005 Delhi Development
Drilling Program and for the purchase of an additional net revenue interest in
one of our existing field. For the nine months ended March 31, 2005, we expended
approximately $1,836,878, in capital expenditures, of which approximately
$725,000 was for the acquisition of producing properties in Tullos Field Area.
Cash provided by financing activities for the nine months ended March 31, 2006
was $1,183,119. This is primarily from loan proceeds of $1,250,000, offset by
$6,754 used to pay off the remaining note for property insurance; $22,654 for
deferred financing fees related to the additional $1MM drawdown from Prospect,
and $37,473 for miscellaneous transaction costs related to equity raising
activities. Comparatively, $3,536,987 was provided in the comparable period
which consisted of $3,855,721 in net proceeds from loans, $1,737,336 payments on
notes, $1,678,307 of gross cash proceeds from the private sale of our common
stock and $259,705 of deferred financing fees.
Budgeted Capital Expenditures. Our 2005 Delhi Development Drilling Program began
in early October, 2005 and completion activities ended in March 2006. As of
March 31, 2006 we had drilled and completed five wells at an estimated total
cost to date of $1.7 million. The two option wells we originally planned for the
2005 program (wells six and seven) were postponed due to heavy rains at Delhi
during January 2006. Further drilling in the Delhi Field is subject to the
completion of the transaction with Denbury Resources, Inc.
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 2, 3, 4 AND 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED
ITEM 1. LITIGATION
On November 17, 2005, a multi-plaintiff 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, or notified of, 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.
During the three months ended March, 2006, we filed our response and Motion to
Stay Proceedings and Dilatory and Declinatory Exceptions with respect to this
proceeding.
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 January 20, 2006, pursuant to Item
1.01, announcing the entry into a material definitive agreement.
Current Report on Form 8-K filed on February 6, 2006, pursuant to Item
1.01, announcing the entry into a material definitive agreement.
Current Report on Form 8-K filed on March 8, 2006, 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: May 22, 2006 By: /s/ STERLING H. MCDONALD
-------------------------------
Sterling H. McDonald
Chief Financial Officer
Principal Financial and Accounting Officer