UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One) FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarter Ended September 30, 2003
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
----------------------------------------------------------------------
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization Identification Number)
500 N. Loop 1604, East, Suite 100, San Antonio, Texas 78232
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code (210) 490-4788
Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or such shorter period that the restraint
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X or No __
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act.) Yes ___ No_X__
The number of shares of the issuer's common stock outstanding as of November
13, 2003 was:
Class Shares Outstanding
Common Stock, $.01 Par Value 35,823,362
1 of 31
ABRAXAS PETROLEUM CORPORATION
FORM 10 - Q
INDEX
PART I
FINANCIAL INFORMATION
ITEM 1 - Financial Statements
Condensed Consolidated Balance Sheets - September 30, 2003
and December 31, 2002......................................3
Condensed Consolidated Statements of Operations -
Three and Nine Months Ended September 30, 2003 and 2002....5
Condensed Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2003 and 2002..............6
Notes to Condensed Consolidated Financial Statements................7
ITEM 2 - Managements Discussion and Analysis of Financial Condition and
Results of Operations.....................................16
ITEM 3 - Quantitative and Qualitative Disclosure about Market Risks.........29
ITEM 4 - Controls and Procedures............................................29
PART II
OTHER INFORMATION
ITEM 1 - Legal proceedings 29
ITEM 2 - Changes in Securities................................................30
ITEM 3 - Defaults Upon Senior Securities......................................30
ITEM 4 - Submission of Matters to a Vote of Security Holders..................30
ITEM 5 - Other Information 29
ITEM 6 - Exhibits and Reports on Form 8-K.....................................30
Signatures ...................................................31
2
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets
(in thousands)
September 30, December 31,
2003 2002
(Unaudited)
------------------ -------------------
Assets:
Current assets:
Cash ................................................... $ 2,428 $ 4,882
Accounts receivable, less allowances for doubtful
accounts:
Joint owners.......................................... 1,581 2,215
Oil and gas production................................ 3,347 7,466
Other................................................. 347 364
------------------ -------------------
5,275 10,045
Equipment inventory........................................... 730 1,014
Other current assets.......................................... 726 1,240
------------------ -------------------
Total current assets........................................ 9,159 17,181
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved.................................................... 322,313 521,995
Unproved, not subject to amortization.............. 4,002 7,052
Other property and equipment................................. 3,575 44,189
------------------ -------------------
Total................................................ 329,890 573,236
Less accumulated depreciation, depletion, and
amortization............................................ 219,514 422,842
------------------ -------------------
Total property and equipment - net........................ 110,376 150,394
Deferred financing fees, net.................................... 4,379 5,671
Deferred income taxes .......................................... - 7,820
Other assets .................................................. 289 329
------------------ -------------------
Total assets.................................................. $ 124,203 $ 181,425
================== ===================
See accompanying notes to condensed consolidated financial statements
3
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets (continued)
(in thousands)
September 30, December 31,
2003 2002
(unaudited)
--------------------- ------------------
Liabilities and Stockholders' Equity (Deficit)
Current liabilities:
Accounts payable.............................................. $ 7,920 $ 9,687
Oil and gas production payable................................ 2,443 2,432
Accrued interest.............................................. 5,065 6,009
Other accrued expenses........................................ 3,018 1,162
Current maturities of long-term debt.......................... - 63,500
-------------------- -------------------
Total current liabilities........................... 18,446 82,790
Long-term debt.................................................. 177,012 236,943
Future site restoration......................................... 1,209 3,946
Stockholders' equity (deficit):
Common Stock, par value $.01 per share-
Authorized 200,000,000 shares; issued, 35,802,612 and 30,145,280
at September 30, 2003 and December 31, 2002 respectively..... 360 301
Additional paid-in capital.................................... 141,159 136,830
Accumulated deficit........................................... (211,967) (269,621)
Receivables from stock sales.................................. (97) (97)
Treasury stock, at cost, 165,883 shares ...................... (964) (964)
Accumulated other comprehensive loss.......................... (955) (8,703)
-------------------- -------------------
Total stockholders' deficit............................... (72,464) (142,254)
-------------------- -------------------
Total liabilities and stockholders' equity (deficit)............ $ 124,203 $ 181,425
==================== ===================
See accompanying notes to condensed consolidated financial statements
4
Abraxas Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
------------------- ----------------- ----------------- -------------------
(In thousands except per share data)
Revenue:
Oil and gas production revenues ...................$ 8,244 $ 10,129 $ 29,277 $ 34,158
Gas processing revenues ........................... - 522 132 1,933
Rig revenues ...................................... 156 169 495 513
Other ............................................ 30 241 67 499
------------------- ----------------- ----------------- -------------------
8,430 11,061 29,971 37,103
Operating costs and expenses:
Lease operating and production taxes .............. 2,372 3,943 7,164 11,205
Depreciation, depletion, and amortization ......... 2,418 5,086 7,861 21,010
Proved property impairment......................... - - - 115,995
Rig operations .................................... 129 143 443 439
General and administrative ........................ 1,143 1,399 3,769 4,578
Stock-based compensation........................... (326) - 467 -
------------------- ----------------- ----------------- -------------------
5,736 10,571 19,704 153,227
------------------- ----------------- ----------------- -------------------
Operating income (loss) .............................. 2,694 490 10,267 (116,124)
Other (income) expense:
Interest income ................................... (5) (15) (22) (56)
Interest expense .................................. 3,911 8,616 12,921 25,790
Amortization of deferred financing fees............ 433 425 1,244 1,283
Financing cost..................................... 581 - 4,182 -
Gain on sale of foreign subsidiaries............... (298) - (67,258) -
Other (income) expense............................. 774 - 774 -
------------------- ----------------- ----------------- -------------------
5,396 9,026 (48,159) 27,017
------------------- ----------------- ----------------- -------------------
Earnings (loss) before cumulative effect of
accounting change and taxes .................... (2,702) (8,536) 58,426 (143,141)
Cumulative effect of accounting change................ - - (395) -
Income tax expense (benefit).......................... - (98) (377) (30,314)
------------------- ----------------- ----------------- -------------------
Net earnings (loss) .............................. $ (2,702) (8,438) 57,654 (112,827)
=================== ================= ================= ===================
Basic earnings (loss) per common share:
Net earnings (loss)............................. (0.08) (0.28) 1.64 (3.76)
Cumulative effect of accounting change.......... - - (0.01) -
------------------- ----------------- ----------------- -------------------
Net earnings (loss) per common share - basic....... $ (0.08) (0.28) 1.63 (3.76)
=================== ================= ================= ===================
Diluted earnings (loss) per common share:
Net earnings (loss)............................. (0.08) (0.28) 1.61 (3.76)
Cumulative effect of accounting change.......... - - (0.01) -
------------------- ----------------- ----------------- -------------------
Net earnings (loss) per common share - diluted.... $ (0.08) (0.28) 1.60 (3.76)
=================== ================= ================= ===================
See accompanying notes to condensed consolidated financial statements
5
Abraxas Petroleum Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
---------------------------------------------
2003 2002
---------------------------------------------
(In thousands)
Operating Activities
Net income (loss)............................................ $ 57,654 $ (112,827)
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities:
Depreciation, depletion, and amortization.................... 7,861 21,010
Proved property impairment................................... - 115,995
Deferred income tax (benefit) expense........................ 377 (30,314)
Amortization of deferred financing fees...................... 1,244 1,283
Amortization of debt discount................................ - 287
Stock-based compensation 467 -
Gain on sale of foreign subsidiaries.......................... (67,258) -
Changes in operating assets and liabilities:
Accounts receivable...................................... 954 499
Equipment inventory...................................... 130 191
Other ................................................... 681 (249)
Accounts payable and accrued expenses.................... 7,477 1,305
----------------- -----------------
Net cash provided by (used in) operating activities........... 9,587 (2,820)
----------------- -----------------
Investing Activities
Capital expenditures, including purchases and development
of properties............................................... (16,327) (33,392)
Proceeds from sale of oil and gas producing properties........ - 33,678
Proceeds from sale of foreign subsidiaries.................... 86,851 -
----------------- -----------------
Net cash provided by investing activities..................... 70,524 286
----------------- -----------------
Financing Activities
Proceeds from long-term borrowings............................ 52,688 17,084
Payments on long-term borrowings.............................. (133,344) (8,176)
Deferred financing fees ...................................... (2,458) (303)
Exercise of stock options ................................... 48 -
Other......................................................... 92 -
----------------- ----------------
Net cash (used in) provided by financing activities........... (82,974) 8,605
----------------- ----------------
Effect of exchange rate changes on cash....................... 409 (318)
----------------- ----------------
(Decrease) increase in cash................................... (2,454) 5,753
Cash, at beginning of period.................................. 4,882 7,605
----------------- ----------------
Cash, at end of period........................................ $ 2,428 $ 13,358
================= ================
Supplemental disclosures of cash flow information:
Cash interest paid............................................ $ 3,298 $ 22,336
================= ================
See accompanying notes to condensed consolidated financial statements
6
Abraxas Petroleum Corporation and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(Unaudited)
September 30, 2002
Note 1. Basis of Presentation
The accounting policies followed by Abraxas Petroleum Corporation and its
subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the
Company's audited financial statements in the Annual Report on Form 10-K filed
for the year ended December 31, 2002, as amended by the annual report on Form
10-K/A No. 1 filed on July 22, 2003. Such policies have been continued without
change. You should also refer to the notes to those financial statements for
additional details of the Company's financial condition, results of operations
and cash flows. All the material items included in those notes have not changed
except as a result of normal transactions in the interim, or as disclosed within
this report. The accompanying interim consolidated financial statements have not
been audited by independent accountants but, in the opinion of management,
reflect all adjustments necessary for a fair presentation of the Company's
financial position and results of operations. Any and all adjustments are of a
normal and recurring nature. The results of operations for the three and nine
months ended September 30, 2003 are not necessarily indicative of results to be
expected for the full year.
The consolidated financial statements include the accounts of the Company
and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("New Grey
Wolf"). In January 2003, the Company sold all of the common stock of its
wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian
Abraxas") and Grey Wolf Exploration Inc. ("Old Grey Wolf"). Certain oil and gas
properties were retained and transferred into New Grey Wolf which was
incorporated in January 2003. The operations of Canadian Abraxas and Old Grey
Wolf are included in the consolidated financial statements through January 23,
2003.
New Grey Wolf's assets and liabilities are translated to U.S. dollars at
period-end exchange rates. Income and expense items are translated at average
rates of exchange prevailing during the period. Translation adjustments are
accumulated as a separate component of shareholders' equity.
The Company has incurred net losses in five of the last six years, and
there can be no assurance that operating income and net earnings will be
achieved in future periods. The Company's revenues, profitability and future
rate of growth are substantially dependent upon prevailing prices for crude oil
and natural gas and the volumes of crude oil, natural gas and natural gas
liquids we produce. The Company's proved reserves will decline as crude oil,
natural gas and natural gas liquids are produced, unless it acquires additional
properties containing proved reserves or conducts successful exploration and
development activities. The Company's ability to acquire or find additional
reserves in the near future will be dependent, in part, upon the amount of
available funds for acquisition, exploration and development projects. Under the
terms of its new senior credit agreement and New Notes (which are described
below), the Company is subject to limitations on capital expenditures. As a
result, the Company may be limited in its ability to replace existing production
with new production and might suffer a decrease in the volume of crude oil and
natural gas it produces. If crude oil and natural gas prices return to depressed
levels or if production levels continue to decrease, the Company's revenues,
cash flow from operations and financial condition may be materially adversely
affected.
Note 2. Income Taxes
The Company records income taxes using the liability method. Under this
method, deferred tax assets and liabilities are determined based on differences
between financial reporting and tax basis of assets and liabilities and are
measured using the enacted tax rates and laws that will be in effect when the
differences are expected to reverse. There is no current or deferred income tax
benefit for the U.S. net operating loss carryforwards due to the valuation
allowance which has been recorded against such benefits.
Note 3. Recent Events
Exchange Offer. On January 23, 2003, the Company completed an exchange
offer, pursuant to which it offered to exchange cash and securities for all of
the outstanding 11 1/2% Senior Secured Notes due 2004, Series A ("Second Lien
Notes") and 11 1/2% Senior Notes due 2004, Series D ("Old Notes"), issued by
7
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
such notes tendered in the exchange offer, tendering note holders received:
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007 ("New Notes"), with a principal
amount equal to $610; and
o 31.36 shares of Abraxas common stock.
Holders of approximately 94% of the aggregate outstanding principal amount
of the Second Lien Notes and Old Notes tendered their notes for exchange in the
offer. Pursuant to the procedures for redemption under the applicable indenture
provisions, the remaining 6% of the aggregate outstanding principal amount of
the Second Lien Notes and Old Notes were redeemed at 100% of the principal
amount plus accrued and unpaid interest.
Redemption of First Lien Notes. On January 24, 2003, the Company completed
the redemption of 100% of its outstanding 12?% Senior Secured Notes due 2003,
Series B ("First Lien Notes"), with the proceeds from the sale of Canadian
Abraxas and Old Grey Wolf.
Note 4. Long-Term Debt
Long-term debt consisted of the following:
September 30 December 31
2003 2002
---------------- -----------------
(In thousands)
11.5% Senior Notes due 2004 ("Old Notes") ............................. $ - $ 801
12.875% Senior Secured Notes due 2003 ("First Lien Notes") ............ - 63,500
11.5% Second Lien Notes due 2004 ("Second Lien Notes")................. - 190,178
11.5% Senior Credit Facility("Grey Wolf Facility") providing for
borrowings up to approximately US $96 million (CDN $150 million)
Secured by the assets of Grey Wolf and non-recourse to Abraxas - 45,964
11.5% Secured Notes due 2007 ("New Notes")............................. 131,605 -
Senior Credit Agreement................................................ 45,407 -
---------------- -----------------
177,012 300,443
Less current maturities ............................................... - 63,500
---------------- -----------------
$ 177,012 $ 236,943
================ =================
New Notes. In connection with the financial restructuring, Abraxas issued
$109.7 million in principal amount of it's 11 1/2% Secured Notes due 2007 in
exchange for the second lien notes and old notes tendered in the exchange offer.
The New Notes were issued under an indenture with U.S. Bank, N. A. In accordance
with SFAS 15, the basis of the New Notes exceeds the face amount of the New
Notes by approximately $19.0 million. Such amount will be amortized over the
term of the New Notes as an adjustment to the yield of the New Notes.
The New Notes accrue interest from the date of issuance, at a fixed annual
rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1,
commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant
to our new senior credit agreement or the intercreditor agreement between the
trustee under the indenture for the New Notes and the lenders under the new
senior credit agreement, to make such cash interest payments in full, we will
pay such unpaid interest in kind by the issuance of additional New Notes with a
principal amount equal to the amount of accrued and unpaid cash interest on the
New Notes plus an additional 1% accrued interest for the applicable period. Upon
an event of default, the New Notes accrue interest at an annual rate of 16.5%.
The New Notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties and are guaranteed by all of Abraxas' current and future
subsidiaries.
The New Notes and related guarantees
8
o are subordinated to the indebtedness under the new senior credit
agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
The New Notes are subordinated to amounts outstanding under the new senior
credit agreement both in right of payment and with respect to lien priority and
are subject to an intercreditor agreement.
Abraxas may redeem the New Notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any New Notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the New Notes during the indicated time periods are as
follows:
Period Percentage
From June 24, 2003 to January 23, 2004...............................91.4592%
From January 24, 2004 to June 23, 2004...............................97.1674%
From June 24, 2004 to January 23, 2005...............................98.5837%
Thereafter..........................................................100.0000%
The indenture also contains customary events of default.
Senior Credit Agreement. In connection with the financial restructuring,
Abraxas entered into a new senior credit agreement providing a term loan
facility and a revolving credit facility as described below. Subject to earlier
termination on the occurrence of events of default or other events, the stated
maturity date for both the term loan facility and the revolving credit facility
is January 22, 2006. Outstanding amounts under both facilities bear interest at
the prime rate announced by Wells Fargo Bank, N.A. plus 4.5%. Any amounts in
default under the term loan facility will accrue interest at an additional 4%.
At no time will the amounts outstanding under the new senior credit agreement
bear interest at a rate less than 9%.
Term Loan Facility. Abraxas borrowed $4.2 million pursuant to a term loan
facility on January 23, 2003, all of which was used to make cash payments in
connection with the financial restructuring. Accrued interest under the term
loan facility will be capitalized and added to the principal amount of the term
loan facility until maturity.
Revolving Credit Facility. Lenders under the new senior credit agreement
have provided a revolving credit facility to Abraxas with a maximum borrowing
base of up to $50 million. Our current borrowing base under the revolving credit
facility is $48.7 million, subject to adjustments based on periodic calculations
and mandatory prepayments under the senior credit agreement. Portions of accrued
interest under the revolving credit facility may be capitalized and added to the
principal amount of the revolving credit facility. As of September 30, 2003, the
balance of the facility was $41.0 million.
Covenants. Under the new senior credit agreement, Abraxas is subject to
customary covenants and reporting requirements.
Security. The obligations of Abraxas under the new senior credit agreement
are secured by a first lien security interest in all of Abraxas' assets,
including all crude oil and natural gas properties.
Guarantees. The obligations of Abraxas under the new senior secured credit
agreement are guaranteed by all of the Company's subsidiaries. The guarantees
under the new senior credit agreement are secured by a first lien security
interest in substantially all of the guarantors' assets, including all crude oil
and natural gas properties.
Events of Default. The new senior credit facility contains customary events
of default, including nonpayment of principal or interest, violations of
covenants, inaccuracy of representations or warranties in any material respect,
cross default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in our financial condition.
9
Note 5. Stock-based Compensation
The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board Opinion ("APB") No. 25,
"Accounting for Stock Issued to Employees," and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's stock at the date of the grant
over the amount an employee must pay to acquire the stock.
Effective July 1, 2000, the Financial Accounting Standards Board ("FASB")
issued FIN 44, "Accounting for Certain Transactions Involving Stock
Compensation", an interpretation of APB No. 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and were not exercised prior to July 1, 2000, require that
the awards be accounted for as variable until they are exercised, forfeited, or
expired. In January 2003, the Company amended the exercise price to $0.66 on
certain options with an existing exercise price greater than $0.66 which results
in variable accounting. The Company recognized a credit of $326,000 and expense
of approximately $467,000 during the three and nine months ended September 30,
2003, respectively, as general and administrative (stock-based compensation)
expense in the accompanying consolidated financial statements. The credit for
the quarter was the result of a lower stock price as of September 30, 2003 as
compared to June 30, 2003.
Pro forma information regarding net income (loss) and earnings (loss) per
share is required by SFAS 123, "Accounting for Stock-Based Compensation" (SFAS
123), which also requires that the information be determined as if the Company
has accounted for its employee stock options granted subsequent to December 31,
1995 under the fair value method prescribed by SFAS 123 The fair value for these
options was estimated at the date of grant using a Black-Scholes option pricing
model with the following weighted-average assumptions for the three and nine
months ended September 30, 2003 and 2002, risk-free interest rates of 1.5%;
dividend yields of -0-%; volatility factor of the expected market price of the
Company's common stock of .35; and a weighted-average expected life of the
option of ten years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
In October 2002, the FASB issued Statement No. 148 "Accounting for
Stock-Based Compensation-Transition and Disclosure", (SFAS No. 148), providing
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. SFAS No. 148 also
amends the disclosure requirement of SFAS No. 123, "Accounting for Stock-Based
Compensation" to include prominent disclosures in annual and interim financial
statements about the method of accounting for stock-based compensation and the
effect of the method used on reported results. The Company adopted the
disclosure provisions of SFAS No. 148 on December 31, 2002.
Had the Company determined stock-based compensation costs based on the
estimated fair value at the grant date for its stock options, the Company's net
income (loss) per share for the three and nine months ended September 30, 2003
and 2002 would have been:
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- --------------------------
2003 2002 2003 2002
------------- ------------ ----------- ------------
Net income (loss) as reported $ (2,702) $ (8,438) $ 57,654 $ (112,827)
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects
(326) - 467 -
Deduct: Total stock-based employee
compensation expense determined under
10
fair value based method for all
awards, net of related tax effects (68) (80) (206) (203)
------------- ------------ ---------- ------------
Pro forma net income (loss) $ (3,096) $ (8,518) $ 57,915 $ (113,030)
============= ============ ========== ============
Earnings (loss) per share:
Basic - as reported $ (0.08) $ (0.28) $ 1.64 $ (3.76)
============= ============ ========== ============
Basic - pro forma $ (0.09) $ (0.29) $ 1.65 $ (3.77)
============= ============ ========== ============
Diluted - as reported $ (0.08) $ (0.28) $ 1.61 $ (3.76)
============= ============ ========== ============
Diluted - pro forma $ (0.09) $ (0.29) $ 1.62 $ (3.77)
============= ============ ========== ============
Note 6. Earnings Per Share
The following table sets forth the computation of basic and diluted earnings
per share:
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------- -----------------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
Numerator:
Net income (loss) before cumulative effect of
accounting change $ (2,702) $ (8,438) $ 58,049 $ (112,827)
Cumulative effect of accounting change (1) - - (395) -
------------- ------------- ------------- -------------
$ (2,702) $ (8,438) $ 57,654 $ (112,827)
============= ============= ============= =============
Denominator:
Denominator for basic earnings per share -
Weighted-average shares 35,781,625 29,979,397 35,205,111 29,979,397
Effect of dilutive securities:
Stock options, warrants and CVR's - - 653,053 -
------------- ------------- ------------- -------------
Dilutive potential common shares Denominator for
diluted earnings per share - adjusted weighted-
average shares and assumed conversions 35,781,625 29,979,397 35,858,164 29,979,397
Basic earnings (loss) per share:
Net income (loss) before cumulative effect
of accounting change $ (0.08) $ (0.28) $ 1.64 $ (3.76)
Cumulative effect of accounting change - - (0.01) -
------------- ------------- ------------- -------------
Net earnings (loss) per common share - basic $ (0.08) $ (0.28) $ 1.63 $ (3.76)
============= ============= ============= =============
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect
of accounting change $ (0.08) $ (0.28) $ 1.61 $ (3.76)
Cumulative effect of accounting change - - (0.01) -
------------- ------------- ------------- -------------
Net earnings (loss) per common share - diluted $ (0.08) $ (0.28) $ 1.60 $ (3.76)
============= ============= ============= =============
(1) The Company adopted SFAS 143 effective January 1, 2003. For the nine months
period ended September 30, 2003 the Company recorded a charge of $395,341 for
the cumulative effect of the change in accounting principle.
For the three and nine months ended September 30, 2002, and for the three
months ended September 30, 2003 none of the shares issuable in connection with
stock options or warrants are included in diluted shares. Inclusion of these
shares would be antidilutive due to losses incurred in the period. Had there not
been losses in these periods, dilutive shares would have been 3,000 shares,
6,487 shares and 834,354 shares for the three and nine months ended September
30, 2002 and for the three months ended September 30, 2003, respectively.
11
Note 7. Business Segments
Business segment information for the three months and nine months ended
September 30, 2003 and 2002 in different geographic areas is as follows:
Three Months Ended September 30, 2003
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 7,176 $ 1,254 $ 8,430
================== ================ ===================
Operating income....................... $ 2,973 $ 279 $ 3,252
================== ================
General Corporate................................................................. (558)
Interest expense and amortization of
deferred financing fees........................................................ (4,920)
Gain on sale of foreign subsidiaries.............................................. 298
Other income (expense) - net...................................................... (774)
-------------------
Loss before income taxes.......................................................... $ (2,702)
===================
Three Months Ended September 30, 2002
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 4,800 $ 6,261 $ 11,061
================== ================= ===================
Operating income........................ $ 651 $ 525 $ 1,176
================== =================
General Corporate................................................................. (686)
Interest expense, financing cost and amortization of
deferred financing fees........................................................ (9,026)
-------------------
Loss before income taxes.......................................................... $ (8,536)
===================
Nine Months Ended September 30, 2003
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 23,193 $ 6,778 $ 29,971
================== ================= ===================
Operating income........................ $ 11,044 $ 2,810 $ 13,854
================== =================
General Corporate................................................................. (3,587)
Interest expense, financing cost and amortization of
deferred financing fees........................................................ (18,325)
Gain on sale of foreign subsidiaries.............................................. 67,258
Other income (expense) - net...................................................... (774)
Cumulative effect of accounting change............................................ (395)
-------------------
Income before income taxes........................................................ $ 58,031
===================
Nine Months Ended September 30, 2002
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 15,175 $ 21,928 $ 37,103
================== ================= ===================
Operating loss.......................... $ (26,187) $ (86,954) $ (113,141)
================== =================
General Corporate................................................................. (2,983)
Interest expense and amortization of
deferred financing fees........................................................ (27,017)
-------------------
Loss before income taxes.......................................................... $ (143,141)
===================
12
At September 30, 2003
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Identifiable assets .................... $ 84,067 $ 34,973 $ 119,040
================== =================
Corporate assets.................................................................. 5,163
-------------------
Total assets ..................................................................... $ 124,203
===================
Note 8. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments
and Certain Hedging Activities. Gains and losses on hedging instruments related
to accumulated Other Comprehensive Income (Loss) and adjustments to carrying
amounts on hedged production are included in natural gas or crude oil production
revenue in the period that the related production is delivered.
Under the terms of our new senior credit agreement, the Company is required to
maintain hedging agreements with respect to not less than 25% nor more than 75%
of it crude oil and natural gas production for a rolling six month period. On
January 23, 2003, the Company entered into a collar option agreement with
respect to 5,000 MMBtu per day, or approximately 25% of the Company's
production, at a call price of $6.25 per MMBtu and a put price of $4.00 per
MMBtu, for the months of February through July 2003. In February 2003, the
Company entered into an additional hedge agreement for 5,000 MMBtu per day with
a floor of $4.50 per MMBtu for the months of March 2003 through February 2004.
In September 2003 the Company entered into an additional hedge agreement for
2,000 MMBtu per day with a floor of $4.00 per MMBtu and 500 Bbl of crude oil per
day with a floor of $22.00 per Bbl. This agreement is for the months of March
and April 2004. The Company incurred cost of $615,000 related to these hedges
for the nine months ended September 30, 2003.
The following table sets forth the Company's hedge position as of September
30, 2003:
Time Period Notional Quantities Price Fair Value
- ---------------------------------------- ------------------------------ ------------------------------ ----------------
March 1, 2003 - February 29, 2004 5,000 MMBtu of natural gas Floor of $4.50 $ 121,591
production per day
March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00 6,534
production per day
March 1, 2004 - April 30, 2004 500 Bbl of crude oil Floor of $22.00 20,147
production per day
----------------
$ 168,272
================
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash
flows of hedged items.
The fair value of the hedging instrument was determined based on the base
price of the hedged item and NYMEX forward price quotes. As of September 30,
2003, a commodity price increase of 10% would have resulted in an unfavorable
change in the fair market value of approximately $16,800 and a commodity price
decrease of 10% would have resulted in a favorable change in fair market value
of approximately $16,800.
Note 9. Contingencies
Litigation. In 2001 the Company and a limited partnership, of which a
subsidiary of the Company is the general partner (the "Partnership"), were named
in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserts breach of contract, fraud and negligent misrepresentation by the Company
and the Partnership related to the responsibility for year 2000 ad valorem taxes
13
on crude oil and natural gas properties sold by the Company and the Partnership.
In February 2002, a summary judgment was granted to the plaintiff in this matter
and a final judgment in the amount of $1.3 million was entered. The Company and
the Partnership have filed an appeal. The Company believes these charges are
without merit. The Company has established a reserve in the amount of $845,000,
which represents the Company's share of the judgment. The Company believes that
the remaining portion of the judgment represents the other partners share of
such judgment.
Additionally, from time to time, the Company is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At September 30, 2003, the Company was not engaged in any legal
proceedings that are expected, individually or in the aggregate, to have a
material adverse effect on the Company.
Note 10. Comprehensive Income
Comprehensive income includes net income, losses and certain items recorded
directly to Stockholder's Equity and classified as Other Comprehensive Income.
The following table illustrates the calculation of comprehensive income
(loss) for the three and nine months ended September 30, 2003 and 2002:
Three Months Ended September 30 Nine Months Ended September 30,
2003 2002 2003 2002
------------ ------------- -------------- -------------
Net income (loss)............................... $ (2,702) $ (8,438) $ 57,654 $ (112,827)
Other Comprehensive loss:
Hedging derivatives (net of tax) - See Note 8 Change
in fair market value of outstanding
hedge positions............................... 34 1,250 (15) 54
Foreign currency translation adjustment.......... (50) 5,523 7,763 3,326
------------ ------------- -------------- -------------
Other comprehensive income (loss).................. $ (2,718) $ (88,917) $ 65,402 $ (110,058)
============ ============= ============== =============
Note 11. Proved Property Impairment
In accordance with the Securities and Exchange Commission requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of a period, or alternatively, if prices
subsequent to that date have increased, a price near the periodic filing date of
the Company's financial statements. As of June 30, 2002, the Company's net
capitalized costs of crude oil and natural gas properties exceeded the present
value of its estimated proved reserves by $138.7 million ($28.2 million on the
U.S. properties and $110.5 million on the Canadian properties). These amounts
were calculated considering June 30, 2002 period-end prices of $26.12 per Bbl
for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the
expected realized prices for each of the full cost pools. The Company used the
subsequent increased prices in Canada to evaluate its Canadian properties, and
reduced the period end June 30, 2002 write-down to an amount of $87.8 million on
those properties. The subsequent prices in the U.S. would not have resulted in a
reduction of the write-down for the U.S. properties. An expense recorded in one
period may not be reversed in a subsequent period even though higher crude oil
and natural gas prices may have increased the ceiling applicable to the
subsequent period. At September 30, 2003 the Company's net capitalized cost of
crude oil and natural gas properties did not exceed the present value of its
estimated reserves and as such no write down was recorded for the three months
ended September 30, 2003.
The Company cannot assure you that it will not experience additional
write-downs in the future. Should commodity prices decline or if any of our
proved reserves are revised downward, a further write-down of the carrying value
of our crude oil and natural gas properties may be required.
Note 12. New Accounting Standards
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
14
requires registrants to classify the costs of mineral rights held under lease or
other contractual arrangement associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically, the
Company has included the costs of such mineral rights associated with extracting
oil and gas as a component of oil and gas properties. If it is ultimately
determined that SFAS No. 142 requires oil and gas companies to classify costs of
mineral rights held under lease or other contractual arrangement associated with
extracting oil and gas as a separate intangible assets line item on the balance
sheet, the Company would be required to reclassify approximately $3.1 million at
September 30, 2003 and December 31, 2002 out of oil and gas properties and into
a separate intangible assets line item. The Company's cash flows and results of
operations would not be affected since such intangible assets would continue to
be depleted and assessed for impairment in accordance with full-cost accounting
rules.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149, among other things, clarifies the
circumstances under which a contract with an initial net investment meets the
characteristic of a derivative and amends the definition of an "underlying" to
conform it to language used in FIN 45. SFAS No. 149 is effective for contracts
entered into or modified after June 30, 2003. The Company adopted this statement
effective July 1, 2003. Implementation of this new standard did not have an
effect on the Company's consolidated financial position or results of
operations. In May 2003, the FASB issued FAS No. 150, entitled "Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity". This statement is effective for financial instruments entered into or
modified after May 31, 2003, and is otherwise effective at the beginning of the
first interim period beginning after June 15, 2003. The Company has no financial
instruments affected by FAS No. 150, therefore adoption by the Company as of
July 1, 2003 will not impact the Company's financial statements. In October
2003, the FASB deferred the effective date of this statement indefinitely.
The American Institute of Certified Public Accountants has issued an
Exposure Draft for a Proposed Statement of Position, " Accounting for Certain
Costs and Activities Related to Property, Plant and Equipment" which would
require major maintenance activities to be expensed as costs are incurred. The
Company is currently evaluating the impact on its results of operations and
financial condition if this proposed Statement of Position is adopted in its
current form.
15
PART I
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following is a discussion of our financial condition, results of
operations, liquidity and capital resources. This discussion should be read in
conjunction with our consolidated financial statements and the notes thereto,
included in our Annual Report on Form 10-K filed for the year ended December 31,
2002 as amended by the annual report on Form 10-K/A No. 1 filed on July 22,
2003. The results of operations of Canadian Abraxas and Old Grey Wolf are
included in this report through January 23, 2003, the date of the consummation
of the sale.
Critical Accounting Policies
There have been no changes from the Critical Accounting Polices described
in our Annual Report on Form 10-K for the year ended December 31, 2002 as
amended by the annual report on Form 10-K/A No. 1 filed on July 22, 2003.
Forward-Looking Information
We make forward-looking statements throughout this document. Whenever you
read a statement that is not simply a statement of historical fact (such as when
we describe what we "believe," "expect" or "anticipate" will occur or what we
"intend" to do, and other similar statements), you must remember that our
expectations may not be correct, even though we believe they are reasonable. The
forward-looking information contained in this document is generally located in
the material set forth under the headings "Management's Discussion and Analysis
of Financial Condition and Results of Operations" but may be found in other
locations as well. These forward-looking statements generally relate to our
plans and objectives for future operations and are based upon our management's
reasonable estimates of future results or trends. The factors that may affect
our expectations regarding our operations include, among others, the following:
o our high debt level;
o our ability to raise capital;
o our limited liquidity;
o economic and business conditions;
o price and availability of alternative fuels;
o political and economic conditions in oil producing countries, especially
those in the Middle East;
o our success in development, exploitation and exploration activities;
o planned capital expenditures;
o prices for crude oil and natural gas;
o declines in our production of crude oil and natural gas;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this document.
In addition to these factors, important factors that could cause actual
results to differ materially from our expectations ("Cautionary Statements") are
disclosed under "Risk Factors" in our Annual Report on Form 10-K for the year
ended December 31, 2002 which is incorporated by reference herein. All
subsequent written and oral forward-looking statements attributable to us, or
persons acting on our behalf, are expressly qualified in their entirety by the
Cautionary Statements.
16
General
We have incurred net losses in five of the last six years, and there can be
no assurance that operating income and net earnings will be achieved in future
periods. Our revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices for crude oil and natural gas and the volumes
of crude oil, natural gas and natural gas liquids we produce. Our proved
reserves will decline as crude oil, natural gas and natural gas liquids are
produced, unless we acquire additional properties containing proved reserves or
conduct successful exploration and development activities. Our ability to
acquire or find additional reserves in the near future will be dependent, in
part, upon the amount of available funds for acquisition, exploitation,
exploration and development projects. Under the terms of our new senior credit
agreement and our new notes, we are subject to limitations on capital
expenditures. As a result, we will be limited in our ability to replace existing
production with new production and might suffer a decrease in the volume of
crude oil and natural gas we produce. If crude oil and natural gas prices return
to depressed levels or if our production levels continue to decrease, our
revenues, cash flows from operations and financial condition will be materially
adversely affected. For more information, see "Liquidity and Capital Resources".
Results of Operations
Our financial results depend upon many factors, particularly the following
factors which most significantly affect our results of operations:
o the sales prices of crude oil, natural gas liquids and natural gas;
o the level of total sales volumes of crude oil, natural gas liquids and
natural gas;
o the ability to raise capital resources and provide liquidity to meet
cash flow needs;
o the level of and interest rates on borrowings; and
o the level and success of exploration and development activity.
Commodity Prices. Our results of operations are significantly affected by
fluctuations in commodity prices. Price volatility in the natural gas market has
remained prevalent in the last few years. In the first nine months of 2003, we
experienced an increase in energy commodity prices from the prices that we
received in the same period of 2002. Price declines experienced in 2001
continued during the first quarter of 2002, primarily due to the economic
downturn. Beginning in March 2002, commodity prices began to increase and
continued higher through 2002 and have continued higher during the first nine
months of 2003.
The table below illustrates how natural gas prices fluctuated over the
eight quarters prior to and including the quarter ended September 30, 2003. The
table below contains the last three day average of NYMEX traded contracts price
and the prices we realized during each quarter presented, including the impact
of our hedging activities.
Natural Gas Prices by Quarter (in $ per Mcf)
----------------------------------------------------------------------------------------------------
Quarter Ended
----------------------------------------------------------------------------------------------------
Dec. 31, March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30,
2001 2002 2002 2002 2002 2003 2003 2003
------------ ----------- ----------- ------------ ----------- ------------- ----------- ------------
Index $ 2.47 $ 2.38 $ 3.36 $ 3.28 $ 3.99 $ 6.61 $ 5.51 $ 5.10
Realized $ 2.09 $ 2.21 $ 2.44 $ 2.08 $ 3.47 $ 5.13 $ 5.11 $ 4.50
The NYMEX natural gas price on November 11, 2003 was $ 4.87 per Mcf.
Prices for crude oil have followed a similar path as the commodity market
fell throughout 2001 and the first quarter of 2002. The table below contains the
last three day average of NYMEX traded contracts price and the prices we
realized during each quarter presented.
17
Crude Oil Prices by Quarter (in $ per Bbl)
-------------------------------------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------------------------------------------------------------
Dec. 31, March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30,
2001 2002 2002 2002 2002 2003 2003 2003
----------- ----------- ------------ -------------- ------------- ----------- ------------ ------------
Index $ 22.12 $ 19.48 $ 26.40 $ 27.50 $ 28.29 $ 33.71 $ 29.87 $ 30.85
Realized $ 18.72 $ 16.64 $ 23.47 $ 23.47 $ 24.83 $ 33.22 $ 28.53 $ 29.52
The NYMEX crude oil price on November 11, 2003 was $31.15 per Bbl.
Hedging Activities. We seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. During the first nine months of 2002, we experienced hedging losses
of $2.5 million. In October 2002, all of these hedge agreements expired. Under
the expired hedge agreements, we made total payments over the term of these
arrangements to various counterparties in the amount of $35.1 million.
Under the terms of our new senior credit agreement, the Company is required to
maintain hedging agreements with respect to not less than 25% nor more than 75%
of it crude oil and natural gas production for a rolling six month period. On
January 23, 2003, the Company entered into a collar option agreement with
respect to 5,000 MMBtu per day, or approximately 25% of the Company's
production, at a call price of $6.25 per MMBtu and a put price of $4.00 per
MMBtu, for the months of February through July 2003. In February 2003, the
Company entered into an additional hedge agreement for 5,000 MMBtu per day with
a floor of $4.50 per MMBtu for the months of March 2003 through February 2004.
In September 2003 the Company entered into an additional hedge agreement for
2,000 MMBtu per day with a floor of $4.00 per MMBtu and 500 Bbl per day of crude
oil with a floor of $22.00 per Bbl. This agreement is for the months of March
and April 2004. We have incurred cost of $615,000 relating to these hedges for
the nine months ended September 30, 2003.
Selected operating data. The following table sets forth certain of our
operating data for the periods presented.
Three Months Ended Nine Months Ended
September 30 September 30
2003 2002 2003 2002
--------------------------------------------------------------------------
Operating Revenue (in thousands):
Crude Oil Sales ................................ $ 1,664 $ 1,801 $ 5,490 $ 4,799
Natural Gas Sales ................................ 6,446 7,277 23,026 26,345
Natural Gas Liquids Sales......................... 134 1,051 761 3,014
Processing Revenue................................ - 522 132 1,933
Rig Operations.................................... 156 169 495 513
Other............................................. 30 241 67 499
----------- ----------- ----------- -----------
$ 8,430 $ 11,061 $ 29,971 $ 37,103
=========== =========== =========== ===========
Operating Income (Loss) (in thousands)............ $ 2,694 $ 490 $ 10,267 $ (116,124)
Crude Oil Production (MBbls)...................... 56 66 180 216
Natural Gas Production (MMcfs).................... 1,432 3,501 4,669 11,692
Natural Gas Liquids Production (MBbls)............ 6 52 31 182
Average Crude Oil Sales Price ($/Bbl)............. $ 29.52 $ 27.19 $ 30.55 $ 22.27
Average Natural Gas Sales Price ($/Mcf)........... $ 4.50 $ 2.08 $ 4.93 $ 2.25
Average Liquids Sales Price ($/Bbl)............... $ 22.72 $ 20.04 $ 24.27 $ 16.53
Comparison of Three Months Ended September 30, 2003 to Three Months Ended
September 30, 2002
Operating Revenue. During the three months ended September 30, 2003,
operating revenue from crude oil, natural gas and natural gas liquid sales
decreased to $8.2 million compared to $10.1 million during three months ended
September 30, 2002. The decrease in revenue was primarily due to decreased
production volumes, primarily due to the sale of our Canadian subsidiaries in
18
January 2003, which was partially offset by higher commodity prices realized
during the period. Higher commodity prices contributed $3.6 million to crude oil
and natural gas revenue while reduced production volumes had a $5.5 million
negative impact on revenue.
Average sales prices net of hedging losses for the quarter ended September
30, 2003 were:
o $ 29.52 per Bbl of crude oil,
o $ 22.72 per Bbl of natural gas liquid, and
o $ 4.50 per Mcf of natural gas
Average sales prices net of hedging losses for the quarter ended September 30,
2002 were:
o $ 27.19 per Bbl of crude oil,
o $ 20.04 per Bbl of natural gas liquid, and
o $ 2.08 per Mcf of natural gas
Crude oil production volumes declined from 66.3 MBbls during the quarter
ended September 30, 2002 to 56.4 MBbls for the same period of 2003. The decline
in production volumes was due to the properties sold in connection with the sale
of Canadian Abraxas and Old Grey Wolf in January 2003. The Canadian properties
sold in January 2003 contributed 9.3 MBbls in the quarter ended September 30,
2002. Natural gas production volumes declined to 1,432 MMcf for the three months
ended September 30, 2003 from 3,501 MMcf for the same period of 2002, primarily
as the result of the sale of Canadian Abraxas and Old Grey Wolf, sold in January
2003, which contributed 2,138 MMcf of natural gas in the third quarter of 2002.
Lease Operating Expenses. Lease operating expenses ("LOE") for the three
months ended September 30, 2003 decreased to $2.4 million from $3.9 million for
the same period in 2002. The decrease in LOE is primarily due the sale of
Canadian Abraxas and Old Grey Wolf in January 2003. LOE related to the
properties owned by Canadian Abraxas and Old Grey Wolf was $2.0 million for the
quarter ended September 30, 2002. Excluding the properties sold, LOE
attributable to on going operations increased, primarily due to higher
production taxes associated with higher commodity prices in the quarter ended
September 30, 2003 as compared to the same period of 2002. Our LOE on a per Mcfe
basis for the three months ended September 30, 2003 was $1.31 per Mcfe compared
to $0.93 for the same period of 2002 primarily due to the decrease in production
volumes.
General and administrative ("G&A") Expenses. G&A expenses decreased from
$1.4 million for the quarter ended September 30, 2002 to $1.1 million for the
same period of 2003. The decrease in G&A expense was primarily due to a
reduction in personnel in connection with the sale of Canadian Abraxas and Old
Grey Wolf on January 23, 2003. G&A expense on a per Mcfe basis was $0.63 for the
third quarter of 2003 compared to $0.33 for the same period of 2002. The per
Mcfe increase was attributable to lower production volumes in the third quarter
of 2003 as compared to the same period of 2002.
Stock-based Compensation Effective July 1, 2000, the Financial Accounting
Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions
Involving Stock Compensation", an interpretation of Accounting Principles Board
Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed
stock option awards which were made subsequent to December 15, 1998, and not
exercised prior to July 1, 2000, require that the awards be accounted for as
variable expenses until they are exercised, forfeited, or expired. In January
2003, we amended the exercise price to $0.66 per share on certain options with
an existing exercise price greater than $0.66 per share which resulted in
variable accounting. We recognized a credit of approximately $326,000 during the
quarter ended September 30, 2003 related to these repricings. The credit was the
result of the price of our common stock being less at September 30, 2003 than it
was on June 30, 2003. During 2002, we did not recognize any stock-based
compensation expense.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization ("DD&A") expense decreased to $2.4 million for the three months
ended September 30, 2003 from $5.1 million for the same period of 2002. The
decrease in DD&A was primarily due to the sale of our Canadian subsidiaries in
January 2003 as well as ceiling limitation write-downs in the second quarter of
2002. Our DD&A on a per Mcfe basis for the quarter ended September 30, 2003 was
$1.34 per Mcfe as compared to $1.21 in 2002. This increase in DD&A on a per Mcfe
basis was due to lower production volumes in the third quarter of 2003 as
compared to the same period of 2002.
19
Interest Expense. Interest expense decreased to $3.9 million for the third
quarter of 2003 compared to $8.6 million for the same period of 2002. The
decrease in interest expense was due to the reduction in long-term debt in the
first nine months of 2003. Long-term debt was reduced as a result of the
transactions which occurred on January 23, 2003 as described in Note 2 in the
Notes to Consolidated Financial Statements.
Income taxes. We have a deferred tax benefit of $98,000 for the three
months ended September 30, 2002. For the period ended September 30, 2003 there
is no current or deferred income tax benefit for net losses due the valuation
allowance which has been recorded against such benefits.
Comparison of Nine months Ended September 30, 2003 to Nine months Ended
September 30, 2002
Operating Revenue. During the nine months ended September 30, 2003,
operating revenue from crude oil, natural gas and natural gas liquid sales
decreased to $29.3 million as compared to $34.2 million in the nine months ended
September 30, 2002. The decrease in revenue was primarily due to decreased
production volumes, primarily due to the sale of our Canadian subsidiaries,
offset by higher realized prices during the period. Decreased production had a
negative impact on revenue of $19.1 million, while increased realized prices
contributed $14.2 million. Production volumes decreased primarily as a result of
producing property sales in the first six months of 2002 as well as the
properties sold in January 2003 in connection with the sale of Canadian Abraxas
and Old Grey Wolf.
Average sales prices net of hedging losses for the nine months ended
September 30, 2003 were:
o $ 30.55 per Bbl of crude oil,
o $ 24.27 per Bbl of natural gas liquid, and
o $ 4.93 per Mcf of natural gas
Average sales prices net of hedging losses for the nine months ended September
30, 2002 were:
o $ 22.27 per Bbl of crude oil,
o $ 16.53 per Bbl of natural gas liquid, and
o $ 2.25 per Mcf of natural gas
Crude oil production volumes declined from 215.5 MBbls during the nine
months ended September 30, 2002 to 179.7 MBbls for the same period of 2003.
Contributing to the decrease in production were properties sold during the
second quarter of 2002 which contributed 13.4 MBbls in the first nine months of
2002 and the Canadian properties sold in January 2003 which contributed 21.1
MBbls during the first nine months of 2002 compared to 15.2 MBbls during the
nine months ended September 30, 2003 (through January 23, 2003). Natural gas
production volumes declined to 4,669 MMcf for the nine months ended September
30, 2003 from 11,692 MMcf for the same period of 2002. As discussed above,
property sales in the second quarter of 2002 and in January 2003 contributed to
the decline in natural gas production volumes. Properties sold in the second
quarter of 2002 contributed 259.5 MMcf during the nine months ended September
30, 2002, through the date of the sale (May 31, 2002). The Canadian properties
sold in January 2003, contributed 7,353 MMcf for the nine months ended September
30, 2002 compared to 345 MMcf for the period ended September 30, 2003 (through
January 23, 2003). This decline was partially offset by new production from
current drilling activities.
Lease Operating Expenses. Lease operating expenses and natural gas
processing costs ("LOE") for the nine months ended September 30, 2003 decreased
to $7.2 million from $11.2 million for the same period in 2002. The decrease in
LOE is primarily due the sale of Canadian Abraxas and Old Grey Wolf in January
2003. LOE related to the properties owned by Canadian Abraxas and Old Grey Wolf
was $5.3 million for the nine months ended September 30, 2002 as compared to LOE
of $0.7 million for the nine months ended September 30, 2003 related to current
Canadian operations. LOE on a per MCFE basis for the nine months ended September
30, 2003 was $1.21 per Mcfe as compared to $0.80 for the same period of 2002.
General and administrative ("G&A") Expenses. G&A expenses decreased from
$4.6 million for the first nine months of 2002 to $3.8 million for the first
nine months of 2003. The decrease in G&A expense was primarily due to a
reduction in personnel in connection with the sale of Canadian Abraxas and Old
20
Grey Wolf on January 23, 2003. G&A expense on a per Mcfe basis was $0.63 for the
first nine months of 2003 compared to $0.33 for the same period of 2002. The per
Mcfe increase was attributable to lower production volumes in the nine month
period ended September 30, 2003 as compared to the same period of 2002.
Stock-based Compensation. Effective July 1, 2000, the Financial Accounting
Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions
Involving Stock Compensation", an interpretation of Accounting Principles Board
Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed
stock option awards which were made subsequent to December 15, 1998, and not
exercised prior to July 1, 2000, require that the awards be accounted for as
variable expenses until they are exercised, forfeited, or expired. In January
2003, we amended the exercise price to $0.66 per share on certain options with
an existing exercise price greater than $0.66 per share. We recognized expense
of approximately $467,000 during the nine months ended September 30, 2003
related to these repricings. During 2002, we did not recognize any stock-based
compensation expense.
Depreciation, Depletion and Amortization Expenses. DD&A expense decreased
to $7.9 million for the nine months ended September 30, 2003 from $21.0 million
for the same period of 2002. The decrease in DD&A was primarily due to the sale
of our Canadian subsidiaries in January 2003 as well as ceiling limitation
write-downs in the second quarter of 2002. Our DD&A on a per Mcfe basis for the
nine months ended September 30, 2003 was $1.32 per Mcfe as compared to $1.49 in
2002. These decreases were due to reduced production volumes in 2002 and
reduction in the full cost pool as a result of prior ceiling limitation
write-downs.
Interest Expense. Interest expense decreased to $12.9 million for the nine
months ended September 30, 2003 compared to $25.8 million for the same period of
2002. The decrease in interest expense was due to the reduction in long-term
debt in the first nine months of 2003. Long-term debt was reduced as a result of
the financial transactions which occurred on January 23, 2003 as described in
Note 2 in the Notes to Consolidated Financial Statements.
Proved Property Impairment. We record the carrying value of our crude oil
and natural gas properties using the full cost method of accounting for crude
oil and natural gas properties. Under this method, we capitalize the cost to
acquire, explore for and develop crude oil and natural gas properties. Under the
full cost accounting rules, the net capitalized cost of crude oil and natural
gas properties less related deferred taxes, is limited by country, to the lower
of the unamortized cost or the cost ceiling, (defined as the sum of the present
value of estimated unescalated future net revenues from proved reserves,
discounted at 10%, plus the cost of properties not being amortized, if any, plus
the lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any, less related income taxes.) If the net
capitalized cost of crude oil and natural gas properties exceeds the ceiling
limit, we are subject to a ceiling limitation write-down to the extent of such
excess. A ceiling limitation write-down is a charge to earnings, which does not
impact cash flow from operating activities. However, such write-downs do impact
the amount of our stockholders' equity. An expense recorded in one period may
not be reversed in a subsequent period even though higher crude oil and natural
gas prices may have increased the ceiling applicable to the subsequent period.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. As of June 30, 2002, our net
capitalized costs of crude oil and natural gas properties exceeded the present
value of our estimated proved reserves by $138.7 million ($28.2 million on the
U.S. properties and $110.5 million on the Canadian properties). As a result,
during the nine months ended September 30, 2002, we incurred a proved-property
impairment write-down of approximately $116 million primarily due to volatile
commodity prices. These amounts were calculated considering June 30, 2002
period-end prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural
gas as adjusted to reflect the expected realized prices for each of the full
cost pools. We used the subsequent prices to evaluate our Canadian properties,
and reduced the period end June 30, 2002 write-down to an amount of $87.8
million on those properties. The subsequent prices in the U.S. would not have
resulted in a reduction of the write-down for the U.S. properties. At September
30, 2003 the Company's net capitalized cost of crude oil and natural gas
properties did not exceed the present value of its estimated reserves and as
such no further write-down was recorded.
21
We cannot assure you that we will not experience additional write-downs in
the future. Should commodity prices decline or if any of our proved reserves are
revised downward, a further write-down of the carrying value of our crude oil
and natural gas properties may be required.
Income taxes. Income tax benefit decreased to $377,000 for the nine months
ended September 30, 2003 from a benefit of $30.2 million for the first nine
months of 2002. The benefit in 2002 was related to the ceiling limitation
write-down that occurred in the second quarter of 2002. There is no current or
deferred income tax benefit for the U.S. net losses due the 100% valuation
allowance which has been recorded against such benefits.
Liquidity and Capital Resources
General. The crude oil and natural gas industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in crude oil and natural gas properties; and
o production and transportation facilities.
The amount of capital available to us will affect our ability to service our
existing debt obligations and to continue to grow the business through the
development of existing properties and the acquisition of new properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, funding under the new senior credit agreement and the sale of
properties. Our overall liquidity depends heavily on the prevailing prices of
crude oil and natural gas and our production volumes of crude oil and natural
gas. Significant downturns in commodity prices, such as that experienced in the
last nine months of 2001 and the first quarter of 2002, can reduce our cash from
operating activities. Although we have hedged a portion of our natural gas and
crude oil production and will continue this practice as required pursuant to the
new senior credit agreement, future crude oil and natural gas price declines
would have a material adverse effect on our overall results, and therefore, our
liquidity. Low crude oil and natural gas prices could also negatively affect our
ability to raise capital on terms favorable to us.
If the volume of crude oil and natural gas we produce decreases, our cash
flow from operations will decrease. Our production volumes will decline as
reserves are produced. In addition, due to sales of properties in 2002 and
January 2003, we now have significantly reduced reserves and production levels.
In the future we may sell additional properties, which could further reduce our
production volumes. To offset the loss in production volumes resulting from
natural field declines and sales of producing properties, we must conduct
successful exploration, exploitation and development activities, acquire
additional producing properties or identify additional behind-pipe zones or
secondary recovery reserves. While we have had some success in pursuing these
activities historically, we have not been able to fully replace the production
volumes lost from natural field declines and property sales.
Working Capital At September 30, 2003, we had current assets of $9.2
million and current liabilities of $18.4 million resulting in a working capital
deficit of $9.2 million. This compares to a working capital deficit of $65.7
million at December 31, 2002 and a working capital deficit of $64.2 million at
September 30, 2002. Current liabilities at September 30, 2003 consisted of trade
payables of $7.9 million, revenues due third parties of $2.4 million, accrued
interest of $5.1 million related to our new notes, of which $4.8 million is
non-cash and other accrued liabilities of $3.0 million. After giving effect to
the scheduled principal reductions required during 2003 under our new senior
credit agreement we will have cash interest expense of approximately $4.0
million. We do not expect to make cash interest payments with respect to the
outstanding new notes, and the issuance of additional new notes in lieu of cash
interest payments thereon will not affect our working capital balance.
Capital expenditures. Capital expenditures during the first nine months of
2003 were $16.3 million compared to $33.4 million during the same period of
2002. The table below sets forth the components of these capital expenditures on
a historical basis for the nine months ended September 30, 2003 and 2002.
22
Nine Months Ended
September 30
-----------------------
2003 2002
-----------------------
Expenditure category (in thousands):
Development .................................... $15,595 $33,240
Facilities and other ........................... 732 152
------- -------
Total ...................................... $16,327 $33,392
======= =======
During the nine months ended September 30, 2003 and 2002, capital
expenditures were primarily for the development of existing properties. For
2003, our capital expenditures are subject to limitations imposed under the new
senior credit facility as amended and new notes, including a maximum annual
capital expenditure budget of $18 million for 2003, and subject to reduction in
the event of a reduction in our net assets. Our Senior Credit facility was
amended on October 30, 2003 allowing for capital expenditures of up to $18
million for 2003, but reducing our capital expenditures limit for 2004 from $10
million to $7 million. Our capital expenditures could include expenditures for
acquisition of producing properties if such opportunities arise, but we
currently have no agreements, arrangements or undertakings regarding any
material acquisitions. We have no material long-term capital commitments and are
consequently able to adjust the level of our expenditures as circumstances
dictate. Additionally, the level of capital expenditures will vary during future
periods depending on market conditions and other related economic factors.
Should the prices of crude oil and natural gas decline from current levels, our
cash flows will decrease which may result in a reduction of the capital
expenditures budget. If we decrease our capital expenditures budget, we may not
be able to offset crude oil and natural gas production volumes decreases caused
by natural field declines and sales of producing properties.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities are summarized in the following
table and discussed in further detail below:
Nine Months Ended
September 30,
----------------------
2003 2002
----------------------
(In thousands)
----------------------
Net cash (used) provided by operating activities ..... $ 9,587 $ (2,820)
Net cash provided by investing activities ............ 70,524 286
Net cash (used) provided by financing activities ..... (82,974) 8,605
-------- --------
Total ................................................ $ (2,863) $ 6,071
======== ========
Operating activities during the nine months ended September 30, 2003
provided $9.6 million cash compared to using $2.8 million in the same period in
2002. Net income plus non-cash expense items during 2003 and net changes in
operating assets and liabilities accounted for most of these funds. Financing
activities used $83.0 million for the first nine months of 2003 compared to
providing $8.6 million for the same period of 2002. Most of these funds were
used to reduce our long-term debt and were generated by the sale of our Canadian
subsidiaries and the exchange offer completed in January 2003. Investing
activities provided $70.5 million for the nine months ended September 30, 2003
compared to using $286,000 for the same period of 2002. The sale of our Canadian
subsidiaries contributed $86.9 million in 2003 reduced by $17.0 million in
exploration and development expenditures. Expenditures in 2002 were primarily
for the development of crude oil and natural gas properties.
Future Capital Resources We will have four principal sources of liquidity
going forward: (i) cash on hand, (ii) cash from operating activities, (iii)
funding under the new senior credit agreement and (iv) sales of producing
properties, however, covenants under the indenture for the outstanding new notes
and the new senior credit agreement restrict our use of cash on hand, cash from
operating activities and any proceeds from asset sales. We may attempt to raise
additional capital through the issuance of additional debt or equity securities,
though the terms of the new note indenture and the new senior credit agreement
substantially restrict our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
23
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all or
substantially all of our assets.
Our best opportunity for additional sources of liquidity and capital will be
through the issuance of equity securities or through the disposition of assets.
Contractual Obligations We are committed to making cash payments in the
future on the following types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of
September 30, 2003:
Payments due in:
Contractual Obligations
(dollars in thousands)
- ----------------------------- --------------------------------------------------------------------------
Total Less than More than 5
one year 1-3 years 3-5 years years
- ----------------------------- ------------- -------------- ------------- ------------- -----------------
Long-Term Debt (1) $ 230,638 $ - $ 46,394 $ 184,244 $ -
Operating Leases (2) 1,281 363 752 166 -
(1) These amounts represent the balances outstanding under the term loan
facility, the revolving credit facility and the new notes. These repayments
assume that interest will be capitalized under the term loan facility and
that periodic interest on the revolving credit facility will be paid on a
monthly basis and that we will not draw down additional funds there under.
(2) Office lease obligations for office space for Abraxas and New Grey Wolf
expire in April 2006 and April 2008, respectively.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties, sales of production payments and borrowings under our bank
credit facilities and other sources. Given our high degree of operating control,
the timing and incurrence of operating and capital expenditures is largely
within our discretion.
Other events
On July 29, 2003 the Company acquired all of the shares of the capital
stock of Wind River Resources Corporation which owned an airplane. The sole
shareholder of Wind River was Robert Watson, Abraxas' Chairman of the Board,
President and Chief Executive Officer. The consideration for the purchase was
106,977 shares of Abraxas common stock and $35,000 in cash. Simultaneously with
this transaction, the airplane was sold. The airplane had previously been made
available to Abraxas' employees for business use.
Long-Term Indebtedness
New Notes . In connection with the financial restructuring, Abraxas issued
$109.7 million in principal amount of it's 11 1/2% Secured Notes due 2007 in
exchange for the second lien notes and old notes tendered in the exchange offer.
The new notes were issued under an indenture with U.S. Bank, N. A. senior
secured credit agreement
24
The new notes accrue interest from the date of issuance, at a fixed annual
rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1,
commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant
to our new senior credit agreement or the intercreditor agreement between the
trustee under the indenture for the new notes and the lenders under the new
senior credit agreement, to make such cash interest payments in full, we will
pay such unpaid interest in kind by the issuance of additional new notes with a
principal amount equal to the amount of accrued and unpaid cash interest on the
new notes plus an additional 1% accrued interest for the applicable period. Upon
an event of default, the new notes accrue interest at an annual rate of 16.5%.
The new notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas,
Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the
New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes.
If Abraxas cannot make payments on the New Notes when they are due, the
guarantors must make them instead.
The new notes and related guarantees:
o are subordinated to the indebtedness under the new senior credit
agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
The new notes are subordinated to amounts outstanding under the new senior
credit agreement both in right of payment and with respect to lien priority and
are subject to an intercreditor agreement.
Abraxas may redeem the new notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any new notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the new notes during the indicated time periods are as
follows:
Period Percentage
From June 24, 2003 to January 23, 2004..............................91.4592%
From January 24, 2004 to June 23, 2004..............................97.1674%
From June 24, 2004 to January 23, 2005..............................98.5837%
Thereafter.........................................................100.0000%
Under the indenture, we are subject to customary covenants which, among other
things, restricts our ability to:
o borrow money or issue preferred stock;o
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral for the notes;
o use assets as security in other transactions; and
o sell certain assets or merge with or into other companies.
In addition, we are subject to certain financial covenants including covenants
limiting our selling, general and administrative expenses and capital
expenditures, a covenant requiring Abraxas to maintain a specified ratio of
25
consolidated EBITDA, as defined in the indenture, to cash interest and a
covenant requiring Abraxas to permanently, to the extent permitted, pay down
debt under the new senior credit agreement and, to the extent permitted by the
new senior credit agreement, the new notes or, if not permitted, paying
indebtedness under the new senior credit agreement.
The indenture also contains customary events of default, including
nonpayment of principal or interest, violations of covenants, inaccuracy of
representations or warranties in any material respect, cross default and cross
acceleration to certain other indebtedness, bankruptcy, material judgments and
liabilities, change of control and any material adverse change in our financial
condition.
New Senior Credit Agreement. In connection with the financial
restructuring, Abraxas entered into a new senior credit agreement providing a
term loan facility and a revolving credit facility as described below. Subject
to earlier termination on the occurrence of events of default or other events,
the stated maturity date for both the term loan facility and the revolving
credit facility is January 22, 2006. In the event of an early termination, we
will be required to pay a prepayment premium, except in the limited
circumstances described in the new senior credit agreement. Outstanding amounts
under both facilities bear interest at the prime rate announced by Wells Fargo
Bank, N.A. plus 4.5%. Any amounts in default under the term loan facility will
accrue interest at an additional 4%. At no time will the amounts outstanding
under the new senior credit agreement bear interest at a rate less than 9%.
Term Loan Facility. Abraxas has borrowed $4.2 million pursuant to a term
loan facility at January 23, 2003, all of which was used to make cash payments
in connection with the financial restructuring. Accrued interest under the term
loan facility will be added to the principal amount of the term loan facility
until maturity.
Revolving Credit Facility. Lenders under the new senior credit agreement
have provided a revolving credit facility to Abraxas with a maximum borrowing
base of up to $50 million. Our current borrowing base under the revolving credit
facility is $48.7 million, subject to adjustments based on periodic calculations
and mandatory prepayments under the senior credit agreement. We have borrowed
$42.5 million under the revolving credit facility, all of which was used to make
cash payments in connection with the financial restructuring. We plan to use the
remaining borrowing availability under the new senior credit agreement to fund
our operations, including capital expenditures. As of September 30, 2003, the
balance of the facility was $40.9 million
Covenants. Under the new senior credit agreement, Abraxas is subject to
customary covenants and reporting requirements. Certain financial covenants
require Abraxas to maintain minimum levels of consolidated EBITDA (as defined in
the new senior credit agreement), minimum ratios of consolidated EBITDA to cash
interest expense and a limitation on annual capital expenditures. In addition,
at the end of the day before the end of each fiscal quarter, if the aggregate
amount of our cash and cash equivalents exceeds $2.0 million, we are required to
repay the loans under the new senior credit agreement in an amount equal to such
excess. The new senior credit agreement also requires us to enter into hedging
agreements on not less than 25% or more than 75% of our projected oil and gas
production. We are also required to establish deposit accounts at financial
institutions acceptable to the lenders and we are required to direct our
customers to make all payments into these accounts. The amounts in these
accounts will be transferred to the lenders upon the occurrence and during the
continuance of an event of default under the new senior credit agreement.
In addition to the foregoing and other customary covenants, the new
senior credit agreement contains a number of covenants that, among other things,
restrict our ability to:
o incur additional indebtedness;
o create or permit to be created any liens on any of our properties;
o enter into any change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations of third parties;
o enter into any forward sales contracts;
26
o make any payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
Security. The obligations of Abraxas under the new senior credit agreement
are secured by a first lien security interest in substantially all of Abraxas'
assets, including all crude oil and natural gas properties.
Guarantees. The obligations of Abraxas under the new senior credit
agreement are guaranteed by Sandia Oil & Gas, Sandia Operating, Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the
new senior credit agreement are secured by a first lien security interest in
substantially all of the guarantors' assets, including all crude oil and natural
gas properties.
Events of Default. The new senior credit agreement contains customary
events of default, including nonpayment of principal or interest, violations of
covenants, inaccuracy of representations or warranties in any material respect,
cross default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in our financial condition.
Hedging Activities.
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. Under the new senior credit agreement, we are required to maintain
hedge positions on not less than 25% or more than 75% of our projected oil and
gas production for a six month rolling period. On January 23, 2003, we entered
into a collar option agreement with respect to 5,000 MMBtu per day, or
approximately 25% of our production, at a call price of $6.25 per MMBtu and a
put price of $4.00 per MMBtu, for the months of February through July 2003. In
February 2003, we entered into a second hedge agreement related to 5,000 MMBtu
for the months of March 2003 through February 2004 which provides for a floor
price of $4.50 per MMBtu. In September 2003 the Company entered into an
additional hedge agreement for 2,000 MMBtu per day with a floor of $4.00 per
MMBtu and 500 Bbl per day of crude oil with a floor of $22.00 per Bbl. This
agreement is for the months of March and April 2004. We incurred cost of
$615,000 related to these hedges for the nine months ended September 30, 2003.
The following table sets forth our hedge position as of September 30, 2003:
Time Period Notional Quantities Price Fair Value
- ---------------------------------------- ------------------------------ ------------------------------ ----------------
March 1, 2003 - February 29, 2004 5,000 MMBtu of natural gas Floor of $4.50 $ 121,591
production per day
March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00 6,534
production per day
March 1, 2004 - April 30, 2004 500 Bbl of crude oil Floor of $22.00 20,147
production per day
----------------
$ 168,272
================
All hedge transactions are subject to our risk management policy, approved
by the Board of Directors. We formally document all relationships between
hedging instruments and hedged items, as well as its risk management objectives
and strategy for undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedged transaction, the nature
of the risk being hedged and how the hedging instrument's effectiveness will be
assessed. Both at the inception of the hedge and on an ongoing basis, we assess
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged items.
Net Operating Loss Carryforwards.
At December 31, 2002 the Company had, subject to the limitation discussed
below, $171.7 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2003 through 2022 if not utilized. At
December 31, 2002, the Company had approximately $1.0 million of net operating
loss carryforwards for Canadian tax purposes. These carryforwards will expire
from 2003 through 2009 if not utilized. In connection with January 2003
financial transactions, certain of the loss carryforwards may be utilized.
27
In addition to the Section 382 limitations, uncertainties exist as to the
future utilization of the operating loss carryforwards under the criteria set
forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $39.7 million and $99.1 million for deferred tax assets
at December 31, 2001 and 2002, respectively. At September 30, 2003 the Company
has established a the 100% valuation allowance to offset the benefit of net
losses.
28
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Commodity Price Risk
Our exposure to market risk rests primarily with the volatile nature of
crude oil, natural gas and natural gas liquids prices. We manage crude oil and
natural gas prices through the periodic use of commodity price hedging
agreements. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources". Assuming the production
levels we attained during the nine months ended September 30, 2003, a 10%
decline in crude oil, natural gas and natural gas liquids prices would have
reduced our operating revenue, cash flow and net income (loss) by approximately
$3.4 million for the nine months ended September 30, 2003.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments
and Certain Hedging Activities". Under SFAS 133, all derivative instruments are
recorded on the balance sheet at fair value.
The fair value of the hedging instrument was determined based on the base
price of the hedged item and NYMEX forward price quotes. As of September 30,
2003, a commodity price increase of 10% would have resulted in an unfavorable
change in the fair market value of approximately $16,800 and a commodity price
decrease of 10% would have resulted in a favorable change in fair market value
of approximately $16,800.
Interest rate risk
As a result of the financial restructuring that occurred in January 2003,
at September 30, 2003 we have $45.4 million in outstanding indebtedness under
the new senior credit agreement, accruing interest at a rate of prime plus 4.5%,
subject to a minimum interest rate of 9.0%. In the event that the prime rate
(currently 4.0%) rises above 4.5% the interest rate applicable to our
outstanding indebtedness under the new senior credit agreement will rise
accordingly. For every percentage point that the prime rate rises above 4.5%,
our interest expense would increase by approximately $454,000 on an annual
basis. Our new notes accrue interest at fixed rates and is accordingly not
subject to fluctuations in market rates.
Foreign Currency
Our Canadian operations are measured in the local currency of Canada. As a
result, our financial results are affected by changes in foreign currency
exchange rates or weak economic conditions in the foreign markets. Canadian
operations reported a pre-tax income of $1.4 million for the nine months ended
September 30, 2003. It is estimated that a 5% change in the value of the U.S.
dollar to the Canadian dollar would have changed our net income by approximately
$72,000. We do not maintain any derivative instruments to mitigate the exposure
to translation risk. However, this does not preclude the adoption of specific
hedging strategies in the future.
Item 4. Controls and Procedures.
- ---------------------------------
As of the end of the period covered by this report, our Chief Executive
Officer and Chief Financial Officer carried out an evaluation of the
effectiveness of Abraxas' "disclosure controls and procedures" (as defined in
the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded
that the disclosure controls and procedures were adequate and designed to ensure
that material information relating to Abraxas and our consolidated subsidiaries
which is required to be included in our periodic Securities and Exchange
Commission filings would be made known to them by others within those entities.
There were no changes in our internal controls that could materially affect, or
are reasonably likely to materially affect our financial reporting during the
third quarter of 2003.
29
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
PART II
OTHER INFORMATION
Item 1. Legal Proceedings
There have been no changes in legal proceedings from that described
in the Company's Annual Report of Form 10-K for the year ended December 31,
2002, and in Note 8 in the Notes to Condensed Consolidated Financial Statements
contained in Part 1 of this report on Form 10-Q.
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 31.1 Certification - Robert L.G. Watson, CEO
Exhibit 31.1 Certification - Chris E. Williford, CFO
Exhibit 32.1 Certification pursuant to 18 U.S.C. Section 1350 -
Robert L.G. Watson, CEO
Exhibit 32.2 Certification pursuant to 18 U.S.C. Section 1350 - Chris
E. Williford, CFO
(b) Reports on Form 8-K:
1. Current Report on Form 8-K filed on August 13,
2003.,Discolsure of Operations and Financial Condition,
including press release announcing Second Quarter 2003
Financial Results.
2. Current Report on Form 8-K filed on October 2, 2003 Regulation
FD, including exhibit of materials presented at Take Stock
Texas Symposium in San Antonio, Texas.
30
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
(Registrant)
Date: November 13, 2003 By:/s/
-------------------- -------------------------------
ROBERT L.G. WATSON,
President and Chief
Executive Officer
Date: November 13, 2003 By:/s/
------------------- -------------------------------
CHRIS WILLIFORD,
Executive Vice President and
Principal Accounting Officer
31