<Page>
As filed with the Securities and Exchange Commission on August 11, 2003.
Registration No. 333-103027
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
POST-EFFECTIVE AMENDMENT NO. 2
TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
Abraxas Petroleum Corporation
Grey Wolf Exploration Inc.
Sandia Oil & Gas Corporation
Sandia Operating Corp.
Wamsutter Holdings, Inc.
Western Associated Energy Corporation
Eastside Coal Company, Inc.
--------------------------------------------------------
(Exact Name of Registrants as Specified in their Charters)
<Table>
Nevada 1331 74-2584033
Alberta 1331 N/A
Texas 1331 74-2368968
Texas 1331 74-2468708
Wyoming 1331 74-2897013
Texas 1331 74-1937878
Colorado 1331 74-2275407
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer Identification
incorporation or organization) Classification Code Number) Number)
</Table>
500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232, (210) 490-4788
--------------------------------------------------------
(Address, including zip code, and telephone number,
including area code, of registrants' principal executive offices)
Robert L. G. Watson
President and Chief Executive Officer
Abraxas Petroleum Corporation
500 North Loop 1604 East, Suite 100
San Antonio, Texas 78232
(210) 490-4788
--------------------------------------------------------
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
With a copy to:
Cox & Smith Incorporated
112 East Pecan, Suite 1800
San Antonio, Texas 78205
Attn: Steven R. Jacobs
(210) 554-5500
--------------------------------------------------------
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As
soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this form are to be
offered on a delayed or continuous basis pursuant to Rule 415 under the
Securities Act of 1933 check the following box. /X/
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act, please check the
following box and list the Securities Act registration statement number of the
earlier effective registration statement for the same offering. / /
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering. / /
If delivery of the prospectus is expected to be made pursuant to
Rule 434, check the following box. / /
THE REGISTRANTS HEREBY AMEND THIS REGISTRATION STATEMENT ON SUCH DATE
OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANTS
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.
ii
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PROSPECTUS
ABRAXAS PETROLEUM CORPORATION
11 1/2% SECURED NOTES DUE 2007, SERIES A
6,592,699 SHARES OF ABRAXAS COMMON STOCK
----------
This prospectus relates to the offering for resale of Abraxas
Petroleum Corporation's 11 1/2% Secured Notes due 2007, Series A, and 6,592,699
shares of common stock of Abraxas Petroleum Corporation. The notes and 5,642,699
shares of common stock were issued in connection with an overall financial
restructuring through a private exchange offer exempt from, or not subject to,
the registration requirements of the Securities Act of 1933, as amended. The
remaining 950,000 shares of common stock represent shares issuable upon exercise
of outstanding warrants. This prospectus will be used by selling security
holders to resell the notes and shares of common stock. We will not receive any
of the proceeds from the sale of notes or common stock by the selling security
holders.
THE 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 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 notes with a principal amount
equal to the amount of accrued and unpaid cash interest on
the notes plus an additional 1% accrued interest for the
applicable period;
- will, upon an event of default, accrue interest at an annual
rate of 16.5%;
- are guaranteed by all of Abraxas' current subsidiaries,
Sandia Oil & Gas Corp., Sandia Operating Corp., Wamsutter
Holdings, Inc., Western Associated Energy Corporation,
Eastside Coal Company, Inc., and our newly-formed,
wholly-owned Canadian subsidiary, Grey Wolf Exploration
Inc., or New Grey Wolf, and will be guaranteed by all of
Abraxas' future subsidiaries;
- are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, our crude
oil and natural gas properties; and
- are not listed on any national securities exchange.
THE ABRAXAS COMMON STOCK
- is currently traded on the American Stock Exchange under the
symbol "ABP." On May 28, 2003, the closing sale price of
Abraxas common stock was $1.03 per share.
----------
YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 12 OF
THIS PROSPECTUS IN EVALUATING AN INVESTMENT IN THE NOTES OR COMMON STOCK.
----------
NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR
DISAPPROVED OF THE NOTES OR THE ABRAXAS COMMON STOCK OR DETERMINED IF THIS
PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
AUGUST 11, 2003
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TABLE OF CONTENTS
<Table>
<Caption>
Page
----
Cautionary Statements Regarding Forward-Looking Information..............................................3
Summary..................................................................................................4
Risk Factors............................................................................................12
Use of Proceeds.........................................................................................22
Ratio of Earnings to Fixed Charges......................................................................22
Capitalization..........................................................................................22
Price Range of Abraxas Common Stock.....................................................................23
Unaudited Pro Forma Condensed Consolidated Financial Statements.........................................24
Selected Historical Financial Data......................................................................29
Management's Discussion and Analysis of Financial Condition and Results of Operations...................31
Business ..............................................................................................50
Management..............................................................................................68
Executive Compensation..................................................................................71
Certain Transactions....................................................................................74
Principal Stockholders..................................................................................75
Selling Security Holders................................................................................76
Plan of Distribution....................................................................................80
Description of the Notes................................................................................82
Description of Capital Stock...........................................................................131
Registration Rights; Liquidated Damages................................................................135
Certain U.S. Federal Income Tax Considerations.........................................................136
Legal Matters..........................................................................................143
Experts................................................................................................143
Where You Can Find More Information....................................................................143
Glossary of Terms......................................................................................144
Index to Financial Statements..........................................................................F-1
</Table>
----------
You should rely only on the information contained in this prospectus
or a document that we have referred you to. We have not authorized anyone to
provide you with information that is different. The delivery of this prospectus
shall not, under any circumstances, create any implication that the information
herein is correct as of any time subsequent to the date hereof.
----------
THE DISTRIBUTION OF THIS PROSPECTUS AND THE SALE OF THE NOTES OR
SHARES OF ABRAXAS COMMON STOCK MAY BE RESTRICTED BY LAW IN CERTAIN
JURISDICTIONS. PERSONS WHO RECEIVE THIS PROSPECTUS OR ANY OF THE NOTES OR SHARES
OF ABRAXAS COMMON STOCK MUST INFORM THEMSELVES ABOUT, AND OBSERVE, ANY SUCH
RESTRICTIONS.
2
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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
We make forward-looking statements throughout this prospectus.
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 prospectus is generally
located in the material set forth under the headings "Summary," "Risk Factors,"
"Business," and "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:
- our high debt level;
- our ability to raise capital;
- our limited liquidity;
- economic and business conditions;
- price and availability of alternative fuels;
- political and economic conditions in oil producing
countries, especially those in the Middle East;
- our success in development, exploitation and exploration
activities;
- planned capital expenditures;
- prices for crude oil and natural gas;
- declines in our production of crude oil and natural gas;
- our acquisition and divestiture activities;
- results of our hedging activities; and
- other factors discussed elsewhere in this prospectus.
3
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SUMMARY
THE FOLLOWING SUMMARIZES THE MORE DETAILED INFORMATION APPEARING
ELSEWHERE IN THIS PROSPECTUS. AS USED IN THIS PROSPECTUS, "ABRAXAS" REFERS TO
ABRAXAS PETROLEUM CORPORATION AND NOT TO ANY OF ITS SUBSIDIARIES, AND "WE,"
"OUR" AND "US" REFER TO ABRAXAS AND ALL OF ITS SUBSIDIARIES. EXCEPT AS OTHERWISE
NOTED, (i) THE RESERVE DATA REPORTED IN THIS PROSPECTUS IS BASED ON THE RESERVE
ESTIMATES OF OUR INDEPENDENT PETROLEUM ENGINEERS, (ii) THE TERMS "ON A PRO FORMA
BASIS" OR "PRO FORMA" REFER TO WHAT OUR BUSINESS MIGHT HAVE LOOKED LIKE IF THE
FINANCIAL RESTRUCTURING DESCRIBED IN THIS PROSPECTUS HAD OCCURRED AT THE TIMES
INDICATED, AND (iii) ALL DOLLAR AMOUNTS REFERENCED IN THIS PROSPECTUS ARE
REFERENCES TO U.S. DOLLARS. SEE "GLOSSARY OF TERMS" FOR DEFINITIONS OF SOME
TECHNICAL TERMS USED IN THIS PROSPECTUS.
ABOUT ABRAXAS
We are an independent energy company engaged primarily in the
acquisition, exploration, exploitation, development and production of crude oil
and natural gas. Our principal means of growth has been through the acquisition
and subsequent development and exploitation of producing properties. As a result
of our historical acquisition activities, we believe we have a substantial
inventory of low risk exploration and development opportunities, the development
of which is critical to the maintenance and growth of our current production
levels. We seek to complement our acquisition and development activities by
selectively participating in exploration projects with experienced industry
partners.
In January 2003, we completed a series of transactions which included
the sale of two of our wholly-owned subsidiaries, Canadian Abraxas Petroleum
Limited, referred to herein as Canadian Abraxas, and Grey Wolf Exploration Inc.,
referred to herein as Old Grey Wolf. Our principal areas of operation are Texas
and western Canada. At December 31, 2002, we owned interests in 548,819 gross
acres (422,874 net acres) applicable to our and operated properties accounting
for 88% of our PV-10, affording us substantial control over the timing and
incurrence of operating and capital expenditures. At December 31, 2002, our
estimated total proved reserves were 166.5 Bcfe with an aggregate PV-10 of
$254.9 million. Subsequent to the transactions described in "Recent Events" our
reserves were reduced by 54.0 Bcfe with an aggregate PV-10 of $118.3 million.
Our principal offices are located at 500 North Loop 1604 East, Suite 100, San
Antonio, Texas 78232 and the telephone number is (210) 490-4788.
FINANCIAL RESTRUCTURING
We recently completed a series of transactions designed to reduce our
indebtedness, improve our ability to meet our debt service obligations and
provide us with working capital necessary to develop our existing crude oil and
natural gas properties. As a result of the financial restructuring, as of
December 31, 2002, on a pro forma basis, we reduced the principal amount of our
overall outstanding indebtedness from approximately $300 million to
approximately $156.4 million and reduced our annual cash interest payments from
approximately $34 million to approximately $4 million, assuming that, as
required under our new senior credit agreement, Abraxas issues additional notes
in lieu of cash interest payments. Although the principal amount of our current
outstanding indebtedness is approximately $156.4 million, due to the accounting
treatment under accounting principles generally accepted in the United States of
America for financial restructurings with respect to the notes, the reported
carrying value of our total outstanding indebtedness will be approximately
$175 million. The transactions comprising the financial restructuring are
summarized below. For a more complete description of the transactions, you
should read the section entitled "Business--Recent Developments--Financial
Restructuring" beginning on page 50.
4
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EXCHANGE OFFER
On January 23, 2003, Abraxas 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, or second lien notes, and
11 1/2% Senior Notes due 2004, Series D, or old notes, issued by Abraxas and
Canadian Abraxas. In exchange for each $1,000 principal amount of notes tendered
in the exchange offer, tendering noteholders received:
- cash in the amount of $264;
- an 11 1/2% Secured Note due 2007, Series A, with a principal
amount equal to $610; and
- 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately
$190.2 million of the second lien notes and $801,000 of the old notes
outstanding. 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, for approximately
$11.5 million ($11.1 million in principal and $0.4 million in interest). The
indentures for the second lien notes and old notes were duly discharged. In
connection with the exchange offer, Abraxas made cash payments of approximately
$47.5 million and issued approximately $109.7 million in principal amount of new
notes and 5,642,699 shares of Abraxas common stock, each of which are being
offered for resale under this prospectus. Fees and expenses incurred in
connection with the exchange offer were approximately $3.8 million.
The accounting treatment for this exchange is such that the carrying
value of the new exchange notes is calculated by reducing the carrying value of
the existing notes, $191.0 million, by the amount of cash paid in the exchange,
$47.5 million, by the market value of the stock issued in the exchange,
$3.8 million, and by the balance of the notes which were redeemed, $11.1
million. This results in a carrying value of $128.6 million. The expenses
related to the exchange offer are expensed as incurred.
The selling security holders identified in this prospectus are the
holders of the notes and shares of Abraxas common stock issued in the exchange
offer. The exchange offer was conducted pursuant to an exemption from the
registration requirements of the Securities Act of 1933, and as such, the notes
and shares of Abraxas common stock issued in the exchange offer are restricted
securities. Pursuant to a registration rights agreement with the dealer manager
for the exchange offer on behalf of the tendering noteholders, we agreed to file
a registration statement with the SEC with respect to the notes and Abraxas
common stock, of which this prospectus forms a part, and to use our reasonable
best efforts to keep the registration statement effective until two years after
its effective date. Upon effectiveness of the registration statement, the notes
and shares of Abraxas common stock will be freely tradable by the selling
security holders and any subsequent purchasers.
SALE OF STOCK OF CANADIAN ABRAXAS AND OLD GREY WOLF
Contemporaneously with the closing of the exchange offer, on
January 23, 2003, Abraxas completed the sale to a wholly-owned subsidiary of
PrimeWest Energy Inc. of all of the outstanding capital stock of two of Abraxas'
former wholly-owned subsidiaries, Canadian Abraxas and Old Grey Wolf, for
approximately $138 million before net adjustments of $3.4 million. Under the
terms of the agreement with PrimeWest, we have retained certain assets formerly
held by Canadian Abraxas and Old Grey Wolf, including all of Canadian Abraxas'
and Old Grey Wolf's undeveloped acreage existing at the time of the sale, which
includes all of our interests in the Ladyfern area. These assets have been
contributed to New Grey Wolf. Portions of this undeveloped acreage will be
developed by PrimeWest and New Grey Wolf under a farmout arrangement.
Abraxas used the proceeds from the sale of the capital stock of
Canadian Abraxas and Old Grey Wolf for the following purposes:
5
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- to pay fees and expenses of the sale of Canadian Abraxas and Old
Grey Wolf of approximately $2.5 million;
- to redeem our outstanding 12 7/8% Senior Secured Notes, Series B,
or first lien notes, at 100% of their principal amount, plus
accrued and unpaid interest, for approximately $66.4 million; and
- to pay approximately $19.4 million of the cash portion of the
exchange offer.
In addition, upon the closing of the sale, Old Grey Wolf repaid all of its
outstanding indebtedness of approximately $46.3 million.
REDEMPTION OF FIRST LIEN NOTES
On January 24, 2003, we completed the redemption of 100% of our
outstanding 12 7/8% Senior Secured Notes, Series B, or first lien notes, with
approximately $66.4 million of the proceeds from the sale of Canadian Abraxas
and Old Grey Wolf. Prior to the redemption, we had $63.5 million of our first
lien notes outstanding. Under the terms of the indenture for the first lien
notes, as of March 15, 2002, we had the right to redeem the first lien notes at
100% of the outstanding principal amount of the notes, plus accrued and unpaid
interest to the date of redemption, and to discharge the indenture upon call of
the first lien notes for redemption and deposit of the redemption funds with the
trustee. We exercised these rights on January 23, 2003 and upon the discharge of
the indenture, the trustee released the collateral securing our obligations
under the first lien notes.
NEW SENIOR CREDIT AGREEMENT
Contemporaneously with the closing of the exchange offer and the sale
of Abraxas' Canadian subsidiaries, 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 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, 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 $49.9 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 March 31, 2003, the outstanding balance was $40.9 million under
the revolving credit facility. We plan to use the remaining borrowing
availability under the new senior credit agreement to fund our operations,
including capital expenditures.
SUMMARY OF THE OFFERING
The selling security holders are offering to sell up to 6,592,699
shares of Abraxas common stock and $113,439,051 principal amount in currently
outstanding notes, in addition to any notes issued in lieu of cash interest
payments thereon. We will not receive any proceeds from the sale of the notes or
common stock. You should read the discussions under the headings "Description of
the Notes" beginning on page 81 and "Description of Capital Stock" beginning on
page 131 for further information regarding the notes and common stock.
6
<Page>
SUMMARY OF THE NOTES
Notes............................ Up to $184 million in principal amount of
11 1/2% Secured Notes due 2007, which
includes approximately $113.4 million
principal amount in currently outstanding
notes, and any notes issued in lieu of cash
interest payments thereon.
Issuer........................... Abraxas Petroleum Corporation
Maturity Date.................... May 1, 2007
Interest Rate and Payment Dates.. The 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 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 notes with a principal amount
equal to the amount of accrued and unpaid
cash interest on the notes plus an additional
1% accrued interest for the applicable
period. The notes will, upon an event of
default, accrue interest at an annual rate of
16.5%.
Guarantees....................... 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 notes,
and all of Abraxas' future subsidiaries will
guarantee the notes. If Abraxas cannot make
payments on the notes when they are due, the
guarantors must make them instead.
Ranking.......................... The notes and related guarantees
- are subordinated to the
indebtedness under the new
senior credit agreement;
- rank equally with all of
Abraxas' current and future
senior indebtedness; and
- rank senior to all of Abraxas'
current and future
subordinated indebtedness, in
each case, if any.
As of March 31, 2003, the amount outstanding
under the new senior credit agreement was
approximately $45.1 million.
Intercreditor Agreement.......... The 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. For more
information on the intercreditor agreement,
see the section entitled "Description of the
Notes--Intercreditor Agreement" beginning on
page 85 of this prospectus.
Collateral....................... The 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.
Optional Redemption.............. Abraxas may redeem some or all of the notes
at any time at the redemption prices
described in the section entitled
"Description of
7
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the Notes--Redemption--Optional Redemption"
on page 83 of this prospectus.
Mandatory Offer to Repurchase.... If Abraxas sells certain assets or
experiences specific kinds of changes of
control, Abraxas must offer to repurchase the
notes, subject to certain limitations in the
case of asset sales, at the prices described
in the sections "Description of the
Notes--Change of Control" and "--Certain
Covenants--Limitation on Asset Sales" on
pages 84 and 90, respectively, of this
prospectus.
Basic Covenants of Indenture..... Abraxas issued the notes under an indenture
with U.S. Bank, N.A. The indenture, among
other things, restricts our ability to:
- borrow money or issue
preferred stock;
- pay dividends on stock or
purchase stock;
- make other asset transfers;
- transact business with
affiliates;
- sell stock of subsidiaries;
- engage in any new line of
business;
- impair the security interest
in any collateral for the
notes;
- use assets as security in
other transactions; and
- sell certain assets or merge
with or into other companies.
The indenture for the notes also includes
certain financial covenants including
covenants limiting Abraxas' selling, general
and administrative expenses and capital
expenditures, a covenant requiring Abraxas to
maintain a specified ratio of consolidated
EBITDA 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 notes or, if not permitted, paying
indebtedness under the new senior credit
agreement.
THE COMMON STOCK
Of the 6,592,699 shares of common stock being offered under this
prospectus, 5,642,699 shares were issued in connection with the financial
restructuring exchange offer and 950,000 shares are issuable upon exercise of
currently outstanding warrants to purchase common stock. Abraxas is currently
authorized to issue a total of 200,000,000 shares of common stock, par value
$.01 per share, and 1,000,000 shares of preferred stock, par value $.01 per
share. As of May 28, 2003, there were 35,630,115 shares of Abraxas common stock
outstanding and no shares of preferred stock outstanding. For a more complete
description of the common stock, see the section entitled "Description of
Capital Stock--Common Stock" beginning on page 131 of this prospectus.
8
<Page>
SUMMARY HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA
The following table presents certain of our summary historical
condensed consolidated financial data and certain pro forma information after
giving effect to and reflecting the exchange offer and each of the other
transactions described under "Business--Recent Developments--Financial
Restructuring". The summary historical financial information, presented below
for each of the three years ended December 31, 2000, 2001 and 2002 and for each
of the three months ended March 31, 2002 and 2003 has been derived from our
consolidated financial statements included in this prospectus. The pro forma
statement of consolidated operations for the year ended December 31, 2002, gives
effect to the exchange offer and each of the other transactions as if they had
occurred on January 1, 2002 and the pro forma statement of operations for the
three months ended March 31, 2003, gives effect to the exchange offer and each
of the other transactions as if they had occurred on January 1, 2002. The
unaudited pro forma information set forth below is not necessarily indicative of
the results that actually would have been achieved had the exchange offer and
each of the other transactions described under "Business--Recent
Developments--Financial Restructuring" been consummated on January 1, 2002 or
that may be achieved in the future. It is important that you read this
information along with "Management's Discussion and Analysis of Financial
Condition and Results of Operations," "Selected Historical Financial Data," our
Consolidated Financial Statements and the notes thereto and the "Unaudited Pro
Forma Condensed Consolidated Financial Statements" included elsewhere in this
prospectus. As discussed in Note 20 to the consolidated financial statements,
the Company's financial statements have been restated.
<Table>
<Caption>
YEARS ENDED DECEMBER 31, THREE MONTHS ENDED MARCH 31,
------------------------ ----------------------------
PRO PRO
FORMA FORMA
2000 2001 2002 2002 2002 2003 2003
---- ---- ---- ---- ---- ---- ----
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
(DOLLARS IN THOUSANDS)
Total operating revenue (1) ............. $ 76,600 $ 77,243 $ 54,320 $ 21,241 $ 11,807 $ 13,111 $ 9,836
Lease and other operating expenses (2) .. 19,500 19,318 15,807 8,264 4,030 2,892 2,347
Depreciation, depletion and amortization
expense ............................... 35,857 32,484 26,539 8,851 6,814 3,142 2,350
Proved property impairment .............. -- 2,638 115,993 32,850 -- -- --
General and administrative expense ...... 6,533 6,455 6,884 5,082 1,698 1,395 1,230
Interest expense, net of interest
income (3) ............................ 30,610 31,445 34,058 15,408 8,380 5,154 5,390
Amortization of deferred financing fee .. 2,091 2,268 2,095 1,724 427 377 434
Financing cost .......................... -- -- 967 -- -- 3,601 --
Gain on sale of foreign subsidiaries .... -- -- -- -- -- 66,960 --
Gain (loss) on sale of equity investment 33,983 (845) -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) ........................... $ 8,449 $ (19,718) $ (118,527) $ (52,106) $ (8,699) $ 62,702 $ (2,502)
Income (loss) per common share:
Basic ................................. $ 0.37 $ (0.76) $ (3.95) $ (1.46) $ (0.29) $ 1.83 $ (0.07)
Diluted ............................... $ 0.26 $ (0.76) $ (3.95) $ (1.46) $ (0.29) $ 1.82 $ (0.07)
OTHER DATA:
Capital expenditures (including
acquisitions) ......................... $ 74,412 $ 57,056 $ 38,714 $ 15,896 $ 17,408 $ 4,589 $ 4,352
Ratio of earnings to fixed charges (4) .. 1.41X n/a n/a n/a n/a 12.5X n/a
</Table>
MARCH 31, 2003 (UNAUDITED)
<Table>
<Caption>
ACTUAL
---------------------
(DOLLARS IN THOUSANDS)
CONSOLIDATED BALANCE SHEET DATA:
Total assets........................... $ 117,674
Total other liabilities................ $ 12,903
Total debt ............................ $ 173,735
Stockholders' deficit.................. $ (70,201)
</Table>
9
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- ----------
(1) Consists of crude oil and natural gas production sales, revenue from rig
operations and other miscellaneous revenue.
(2) Consists of lease operating expenses, production taxes and rig operating
expenses.
(3) Interest expense on our indebtedness includes cash interest expense on the
new revolving credit facility and non-cash (additional notes) interest
expense on the term loan and the new notes. Non-cash interest expense is
calculated at 9% on the term loan and at an imputed rate of 8.6% on the new
notes based on the carrying value of the exchanged notes of $128.6 million.
(4) Earnings consist of income (loss) from before income taxes plus fixed
charges. Fixed charges consist of interest expense, amortization of
deferred financing fees and premium on the old notes. Our earnings were
inadequate to cover fixed charges in 2001, 2002 and Pro Forma 2002, by ,
$15.6 million, $148.2 million, and $52.1 million, respectively. In 2000, we
had earnings of $46.7 million and fixed charges of $33.2 million. Our ratio
of earnings to fixed charges during 2000 was 1.41x. For the quarter ended
March 31, 2002 our earnings were inadequate to cover fixed charges by
$9.5 million, for the quarter ended March 31, 2003 we had earnings of
$69.0 million and fixed charges of $5.5 million. Our ratio of earnings to
fixed charges for March 31, 2003 was 12.5x.
SUMMARY HISTORICAL AND PRO FORMA OPERATING DATA
<Table>
<Caption>
YEARS ENDED DECEMBER 31, THREE MONTHS ENDED MARCH 31,
------------------------ ----------------------------
PRO PRO
FORMA FORMA
2000 2001 2002 2002 2002 2003 2003
---- ---- ---- ---- ---- ---- ----
(dollars in thousands, except per unit data)
PRODUCTION:
Crude oil (MBbls)..................... 637 454 292 251 74 65 63
NGLs (MBbls).......................... 315 278 242 9 68 20 4
Natural gas (MMcf).................... 19,963 17,496 15,453 5,420 3,973 1,965 1,406
MMcfe................................. 25,672 21,888 18,658 6,980 4,825 2,475 1,808
AVERAGE SALES PRICE:(1)
Crude oil (per Bbl)................... $ 18.69 $ 24.63 $ 24.34 $ 24.95 $ 16.64 $ 33.22 $ 33.33
NGLs (per Bbl)........................ 22.42 21.51 17.94 14.89 $ 12.76 $ 25.29 $ 26.28
Natural gas (per Mcf)................. 2.71 3.20 2.55 2.61 2.21 5.13 5.29
Per Mcfe.............................. 2.82 3.35 2.72 2.94 2.26 5.16 5.34
AVERAGE COST OF PRODUCTION (PER MCFE).... $ 0.74 $ 0.85 $ 0.82 $ 1.10 $ 0.81 $ 1.11 $ 1.30
</Table>
- ----------
(1) Average sales prices include effects of hedging activities.
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SUMMARY HISTORICAL AND PRO FORMA RESERVES DATA
The following table sets forth summary information with respect to our
estimated proved crude oil, NGLs and natural gas reserves as of the dates
indicated and sets forth an unaudited summary report of our pro forma reserves
as of December 31, 2002 and gives effect to and reflects the exchange offer and
each of the other transactions described under "Business--Recent
Developments--Financial Restructuring" as if all were consummated as of such
dates. The information in these tables should be read in conjunction with the
section entitled "Unaudited Pro Forma Condensed Consolidated Financial
Statements" included elsewhere in this prospectus.
<Table>
<Caption>
AS OF DECEMBER 31,
-----------------------------------------------------
PRO
FORMA
2000 2001 2002 2002
---- ---- ---- -----
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT DATA)
ESTIMATED PROVED RESERVES:
Crude oil and NGLs (MBbls)............................................ 8,844 6,802 4,605 3,459
Natural gas (MMcf).................................................... 191,327 188,757 138,832 91,766
Natural gas equivalents (MMcfe)....................................... 244,391 229,569 166,462 112,520
% Proved developed.................................................. 67% 62% 65% 48%
Estimated future net revenue before income taxes...................... $ 1,727,909 $ 386,762 $ 460,989 $ 276,746
PV-10................................................................. 1,006,521 209,666 254,853 136,584
% Proved developed.................................................. 68% 82% 81% 65%
</Table>
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RISK FACTORS
YOU SHOULD CAREFULLY CONSIDER THE FOLLOWING RISK FACTORS IN ADDITION
TO THE OTHER INFORMATION IN THIS PROSPECTUS BEFORE MAKING AN INVESTMENT IN THE
NOTES OR ABRAXAS COMMON STOCK OFFERED BY THE SELLING SECURITY HOLDERS.
RISKS RELATED TO THE OFFERING
THE SECURITY FOR THE NOTES MAY BE INADEQUATE TO SATISFY ALL AMOUNTS
DUE AND OWING TO THE HOLDERS OF OUR NOTES. Currently, the notes are secured by a
second lien or charge on all of our current and future assets, including, but
not limited to, our crude oil and natural gas assets. There can be no assurance
that, following an acceleration after an event of default under the indenture
for the notes, the proceeds from the sale of the collateral and allocable to the
notes would be sufficient to satisfy all amounts due on such notes. The ability
of the holders of the notes to realize upon the collateral will also be subject
to certain limitations in the indenture for the notes, the accompanying mortgage
and the pledge agreement, including a prohibition on foreclosing on the
collateral for 180 days after an event of default under the notes, as
applicable. In addition, if we become a debtor in a case under the bankruptcy
code, the automatic stay imposed by the bankruptcy code would prevent the
trustee from selling or otherwise disposing of the collateral without bankruptcy
court authorization. In that case, the foreclosure might be delayed
indefinitely. See "Description of the Notes--Security" on page 83 of this
prospectus.
THE GUARANTEES MAY NOT BE ENFORCEABLE IN BANKRUPTCY. Abraxas'
obligations under the notes (and any additional notes issued in lieu of cash
interest payments), are guaranteed by Sandia Oil & Gas, Sandia Operating,
Wamsutter, New Grey Wolf, Western Associated Energy, Eastside Coal and any other
future subsidiaries. Various fraudulent conveyance laws have been enacted for
the protection of creditors and may be utilized by courts to subordinate or void
such guarantees. It is also possible that under certain circumstances a court
could hold that the direct obligations of a guarantor could be superior to the
obligations under its guarantee.
To the extent that a court were to find that at the time a guarantor
entered into a guarantee either:
(1) the guarantee was incurred by the guarantor with the intent
to hinder, delay or defraud any present or future creditor
or that the guarantor contemplated insolvency with a design
to favor one or more creditors to the exclusion in whole or
in part of others; or
(2) the guarantor did not receive fair consideration or
reasonably equivalent value for issuing the guarantee and,
at the time it issued the guarantee, the guarantor
- was insolvent or rendered insolvent by reason of the
issuance of the guarantee;
- was engaged or about to engage in a business or transaction
for which the remaining assets of the guarantor constituted
unreasonably small capital; or
- intended to incur, or believed that it would incur, debts
beyond its ability to pay such debts as they matured;
the court could void or subordinate the guarantee in favor of the guarantor's
other creditors. Among other things, a legal challenge of a guarantee issued by
a guarantor on fraudulent conveyance grounds may focus on the benefits, if any,
realized by the guarantor as a result of our issuance of the notes or any
additional notes issued in lieu of cash interest payments. A court might find
that the guarantors did not benefit from incurrence of the indebtedness
represented by such notes.
To the extent that a guarantee is voided as a fraudulent conveyance or
found unenforceable for any other reason, holders of the notes or any additional
notes issued in lieu of cash interest payments would cease to have any claim in
respect of the applicable guarantor. In such event, the claims of the holders of
the notes against such guarantor would be subject to the prior payment of all
liabilities and preferred stock claims of such guarantor. There can be no
assurance that, after providing for all claims and preferred stock interests, if
any, there would be sufficient assets to satisfy the claims of the holders of
the notes relating to any voided portion of such guarantee.
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Under applicable provisions of Canadian federal bankruptcy law or
comparable provisions of provincial fraudulent preference laws, if a court in an
action brought by an unpaid creditor of New Grey Wolf or by a bankruptcy trustee
thereof were to find that the liens granted by New Grey Wolf over its assets
were intended to prefer the holders of the notes over other creditors, such
liens could be set aside. This would become an issue if New Grey Wolf became
insolvent or bankrupt within a certain period after granting the liens.
UNDER CERTAIN CIRCUMSTANCES A BANKRUPTCY COURT COULD ORDER THE
REPAYMENT OF INTEREST PAYMENTS MADE UNDER THE NOTES. The bankruptcy code allows
the bankruptcy trustee (or us, acting as debtor-in-possession) to avoid certain
transfers of a debtor's property as a "preference." Under the bankruptcy code a
preference is:
- a transfer of the debtor's property;
- to or for the benefit of a creditor on account of an
existing debt;
- made while the debtor was insolvent (presumed in the 90 days
before a bankruptcy filing);
- if the creditor receives more than it would have received in
a bankruptcy liquidation if the transfer had not been made;
and
- if the transfer/payment was made in the 90 days before the
bankruptcy filing, or, if the creditor was an "insider"
within one year before the bankruptcy filing (a creditor
that is also a director, officer or controlling stockholder
of a debtor may be deemed to be an insider).
Our payment of principal and/or accrued interest, or our grant of a
lien or security interest, including payments made or liens or security
interests granted pursuant to the exchange offer, may be deemed to be a
preference if all of the factors discussed above are present. If such transfers
were deemed to be preferential transfers, the payments could be recovered from
the noteholders and the lien or security interest could be avoided.
If the notes (and any additional notes issued in lieu of cash interest
payments), are fully secured (i.e., the value of collateral exceeds the amount
it secures), payments on such notes would not constitute preferential transfers.
However, if, or to the extent, the notes are undersecured (i.e., the value of
the collateral is less than the amount which it secures), payments would be
deemed to have been applied, first, to the unsecured portion of the notes and,
second, to the secured portion of the notes and the payments attributable to the
unsecured portion could be considered preferential transfers. Therefore, if we
are involved in a bankruptcy proceeding, holders of our notes or any additional
notes issued in lieu of cash interest payments may be required to disgorge
payments made on such notes to the extent the notes are undersecured.
Additionally, due to Abraxas' and the guarantors' being domiciled in
the United States and in Canada, Abraxas and the guarantors could be subject to
multi-jurisdictional insolvency proceedings in the United States and Canada. If
multi-jurisdictional insolvency proceedings were to occur, this could result in
additional delay in payment of the notes or any additional notes issued in lieu
of cash interest payments, as well as delay in or prevention from enforcing
remedies under such notes, any guarantee thereunder and the liens securing such
notes and the guarantees. Likewise, our notes could be subject to different
treatment inasmuch as the multiple insolvency proceedings would be conducted by
different courts applying different laws.
IN BANKRUPTCY, THE PAYMENT OF CASH AND THE ISSUANCE OF THE NOTES AND
ABRAXAS COMMON STOCK IN THE EXCHANGE OFFER COULD BE AVOIDED AS A PREFERENTIAL
TRANSFER. If we were to become subject to a petition for relief under the
bankruptcy code within 90 days after the consummation of the exchange offer (or,
with respect to any insiders specified in the bankruptcy code, within one year
after consummation of the exchange offer) and certain other conditions are met,
the consideration paid to noteholders in the exchange offer, absent the presence
of one of the bankruptcy code defenses to avoidance, could be avoided as a
preferential transfer and, to the extent avoided, the value of such
consideration could be recovered from the noteholder and possibly from
subsequent transferees.
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<Page>
ORIGINAL ISSUE DISCOUNT WILL BE INCLUDED IN YOUR GROSS INCOME FOR U.S.
FEDERAL INCOME TAX PURPOSES BEFORE YOU RECEIVE ANY CASH PAYMENTS ON THE NOTES.
The notes have been deemed to be issued at a substantial discount from their
stated principal amount at maturity because the issue price of the notes will be
determined by reference to the fair market value of the second lien notes and
old notes in exchange for which the notes subject to this prospectus were issued
on January 23, 2003, the closing date of the private exchange offer in which the
notes were issued. Furthermore, periodic interest payments on the notes will be
payable in cash or by the issuance of additional notes and, as such, will be
treated as if all interest payments are made in the form of additional notes,
thereby creating additional original issue discount on the notes. Consequently,
prior to receiving any cash interest payments on the notes, a holder of notes
will be required to include significant original issue discount in the gross
income of such holder for U.S. federal income tax purposes. For a more detailed
discussion of the tax consequences applicable to holders of the notes, see the
section entitled "Certain U.S. Federal Income Tax Considerations" beginning on
page 136 of this prospectus.
THE AMOUNT OF ANY CLAIM MADE BY A NOTE HOLDER IN A BANKRUPTCY ACTION
MAY BE LIMITED AS A RESULT OF THE NOTES BEING ISSUED WITH ORIGINAL ISSUE
DISCOUNT. If a bankruptcy petition is filed by or against us under the U.S.
Bankruptcy Code while the notes are outstanding, the claim of a holder of the
notes with respect to the accreted value of the notes may be limited to an
amount equal to the sum of:
- the initial issue price for the notes; and
- that portion of the original issue discount that is not
deemed to constitute "unmatured interest" within the meaning
of the United States Bankruptcy Code.
Any original issue discount that was not amortized as of the date of
any such bankruptcy filing would constitute "unmatured interest." Accordingly,
holders of the notes under such circumstances may receive a lesser amount than
they would be entitled to under the express terms of the indenture for the
notes, even if sufficient funds are available. In addition, to the extent that
the U.S. Bankruptcy Code differs from the Internal Revenue Code of 1986, as
amended, in determining the method of amortization of original issue discount, a
holder of the notes may realize taxable gain or loss upon payment of that
holder's claim in bankruptcy.
WE MAY NOT BE ABLE TO REPURCHASE THE NOTES UPON A CHANGE OF CONTROL.
Upon the occurrence of certain change of control events, holders of the notes
may require us to offer to repurchase all or any part of their notes. We may not
have sufficient funds at the time of the change of control to make the required
repurchases of such notes.
The source of funds for any repurchase required as a result of any
change of control will be our available cash or cash generated from crude oil
and natural gas operations or other sources, including borrowings, sales of
assets, sales of equity or funds provided by a new controlling entity. We cannot
assure you, however, that sufficient funds would be available at the time of any
change of control to make any required repurchases of the notes tendered.
Furthermore, using available cash to fund the potential consequences of a change
of control may impair our ability to obtain additional financing in the future.
In addition, the new senior credit agreement restricts our ability to repurchase
the notes. Any future credit agreements or other agreements relating to debt to
which we may become a party will most likely contain similar restrictions and
provisions.
AN ACTIVE MARKET MAY NOT DEVELOP FOR THE NOTES OR ABRAXAS COMMON
STOCK. The notes were originally issued on January 23, 2003 and no assurance can
be given that an active market will develop, or, if such a market develops, that
such market will be liquid. The notes will not be listed on any national
securities exchange. Accordingly, no assurance can be given that a holder of the
notes will be able to sell such notes in the future or as to the price at which
such sale may occur. The liquidity of the market for the notes and the prices at
which such notes trade will depend upon the amount outstanding, the number of
holders thereof, the interest of securities dealers in maintaining a market in
such notes and other factors beyond our control. The liquidity of, and trading
market for, the notes also may be adversely affected by general declines in the
market for high yield securities. Such declines may adversely affect the
liquidity and trading markets for the notes.
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The Abraxas common stock is quoted on the American Stock Exchange.
While there is currently one specialist in the Abraxas common stock, this
specialist is not obligated to continue to make a market in the Abraxas common
stock. In this event, the liquidity of the Abraxas common stock could be
adversely impacted and a stockholder could have difficulty obtaining accurate
stock quotes.
COMPOUND INTEREST ON THE NOTES MAY BE RESTRICTED BY APPLICABLE LAW.
Interest on the notes will compound semi-annually to the extent permitted by
applicable law. Although applicable law provides for enforceability of compound
interest in certain loans and agreements, it may not be enforceable in a loan
with a principal amount of $250,000 or less. It is unclear whether compound
interest is enforceable in a loan with a principal amount of $250,000 or less
when the aggregate amount of the debt incurred under the financing agreement
governing that loan is over $250,000. Accordingly, the ability of the holder of
any note with a principal amount of $250,000 or less to collect compounded
interest may be restricted by applicable law. In any event, Abraxas intends to
pay compound interest in accordance with the terms of the indenture for the
notes.
ABRAXAS DOES NOT PAY DIVIDENDS ON COMMON STOCK. Abraxas has never paid
a cash dividend on its common stock and the terms of the new senior credit
agreement and the indenture relating to the notes limit the ability of Abraxas
to pay dividends on its common stock.
SHARES ELIGIBLE FOR FUTURE SALE MAY DEPRESS OUR STOCK PRICE. At
May 28, 2003 we had 35,630,115 shares of common stock outstanding of which
7,293,445 shares were held by affiliates, 3,293,302 shares of common stock were
subject to outstanding options granted under certain stock option plans (of
which 2,215,788 shares were vested at May 28, 2003) and 950,000 shares were
issuable upon exercise of warrants.
All of the shares of common stock held by affiliates are restricted or
control securities under Rule 144 promulgated under the Securities Act. The
shares of the common stock issuable upon exercise of the stock options have been
registered under the Securities Act. The shares of the common stock issuable
upon exercise of the warrants are subject to certain registration rights and,
therefore, will be eligible for resale in the public market after a registration
statement covering such shares has been declared effective. Sales of shares of
common stock under Rule 144 or another exemption under the Securities Act or
pursuant to a registration statement could have a material adverse effect on the
price of the common stock and could impair our ability to raise additional
capital through the sale of equity securities.
THE PRICE OF ABRAXAS' COMMON STOCK HAS BEEN VOLATILE AND COULD
CONTINUE TO FLUCTUATE SUBSTANTIALLy. Abraxas' common stock is traded on the
American Stock Exchange. The market price of Abraxas' common stock has been
volatile and could fluctuate substantially based on a variety of factors,
including the following:
- Fluctuations in commodity prices;
- Variations in results of operations;
- Legislative or regulator changes;
- General trends in the industry;
- Market conditions; and
- Analysts' estimates and other events in the crude oil and
natural gas industry.
WE MAY ISSUE SHARES OF PREFERRED STOCK WITH GREATER RIGHTS THAN OUR
COMMON STOCK. Subject to the rules of the American Stock Exchange, our articles
of incorporation authorize our board of directors to issue one or more series of
preferred stock and set the terms of the preferred stock without seeking any
further approval from holders of our common stock. Any preferred stock that is
issued may rank ahead of our common stock in terms of dividends, priority and
liquidation premiums and may have greater voting rights than our common stock.
ANTI-TAKEOVER PROVISIONS COULD MAKE A THIRD PARTY ACQUISITION OF
ABRAXAS DIFFICULT. Abraxas' articles of incorporation and by-laws provide for a
classified board of directors, with each member serving a three-year term, and
eliminate the ability of stockholders to call special meetings or take action by
written
15
<Page>
consent. Abraxas also has adopted a stockholder rights plan. Each of the
provisions in the articles of incorporation and by-laws and the stockholder
rights plan could make it more difficult for a third party to acquire Abraxas
without the approval of Abraxas' board. In addition, the Nevada corporate
statute also contains certain provisions that could make an acquisition by a
third party more difficult.
RISKS RELATED TO OUR BUSINESS
OUR REDUCED OPERATING CASH FLOW RESULTING FROM THE SALE OF CANADIAN
ABRAXAS AND OLD GREY WOLF MAY PUT SIGNIFICANT STRAIN ON OUR LIQUIDITY AND CASH
POSITION. Our reduced operating cash flow and resulting limited liquidity has
caused us, and the limitations imposed by the new senior credit agreement and
the notes will cause us, to reduce capital expenditures, including exploration,
exploitation and development projects. These reductions will limit our ability
to replenish our depleting reserves, which could negatively impact our cash flow
from operations and results of operations in the future. In addition, under the
terms of the notes, we are required, to the extent permitted, to permanently pay
down debt under the new senior credit agreement and, if permitted, the notes,
with our cash flow which is not required to pay our capital expenditures or make
cash interest and tax payments.
The effects of our reduced operating cash flow will be exacerbated by
our high level of debt, which will affect our operations in several important
ways, including:
- A substantial amount of our cash flow from operations could
be required to make principal and interest payments on our
outstanding indebtedness and may not be available for other
purposes, including developing our properties;
- The covenants contained in the indenture governing the notes
and in the new senior credit agreement will limit our
ability to borrow additional funds or to dispose of assets
or use the proceeds of any asset sales and may affect our
flexibility in planning for, and reacting to, changes in our
business; and
- Our debt level may impair our ability to obtain additional
financing in the future for working capital, capital
expenditures, acquisitions, interest payments, scheduled
principal payments, general corporate purposes or other
purposes.
OUR LIMITED LIQUIDITY AND RESTRICTIONS ON USES OF CASH DICTATED BY
BOTH THE NEW SENIOR CREDIT AGREEMENT AND THE NOTES, COMBINED WITH OUR HIGH DEBT
LEVELS MAY HINDER OUR ABILITY TO SATISFY THE SUBSTANTIAL CAPITAL REQUIREMENTS
RELATED TO OUR OPERATIONS. The success of our future operations will require us
to make substantial capital expenditures for the exploitation, development,
exploration and production of crude oil and natural gas. Volatile commodity
prices could negatively impact our cash flow from operations as well as any
future sales of producing properties.
Under the terms of the new senior credit agreement, we are 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. We will also be required to make mandatory repayments
of the outstanding amounts owing under the new senior credit agreement if the
outstanding amounts exceed the borrowing base. In addition, under the terms of
the notes, Abraxas is subject to cash and expenditures covenants including those
set forth in the sections entitled "Description of the Notes--Certain
Covenants--Excess Cash Flow and Excess Cash," "--Limitations on Expenditures for
Selling, General and Administrative Expenses," "--Limitations on Capital
Expenditures" and "--Limitation on Uses of Cash" beginning on page 95 of this
prospectus.
These limitations imposed on Abraxas by the new senior credit
agreement and the notes may have the effect of limiting our ability to develop
our crude oil and natural gas properties because much of our cash flow may be
used for debt service. As a result, our ability to replace production may be
limited. You should read the discussion under "--Our ability to replace
production with new reserves is highly dependent on acquisitions or successful
development and exploration activities" for more information regarding the risks
associated with limitations on our ability to develop our crude oil and natural
gas properties.
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HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS. Under the terms of
the new senior credit agreement, we are required to maintain commodity price
hedging positions on not less than 25% and not more than 75% of our estimated
production for a rolling six-month period. In January 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 calendar months of February through July 2003. In
February 2003, we entered into a second hedging agreement related to 5,000 MMBtu
which provides for a floor price of $4.50 per MMBtu for the calendar months of
March 2003 through February 2004. For a more detailed description of the new
senior credit agreement and our hedging sensitivity, see the section entitled
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" beginning on page 31.
We cannot assure you that our hedging transactions will reduce risk or
minimize the effect of any decline in crude oil or natural gas prices. Any
substantial or extended decline in crude oil or natural gas prices would have a
material adverse effect on our business and financial results. Hedging
activities may limit the risk of declines in prices, but such arrangements may
also limit, and have in the past limited, additional revenues from price
increases. In addition, such transactions may expose us to risks of financial
loss under certain circumstances, such as:
- production being less than expected; or
- price differences between delivery points for our production
and those in our hedging agreements increasing.
In 2000, 2001 and 2002, we experienced hedging losses of
$20.2 million, $12.1 million and $3.2 million, respectively.
OUR ABILITY TO REPLACE PRODUCTION WITH NEW RESERVES IS HIGHLY
DEPENDENT ON ACQUISITIONS OR SUCCESSFUL DEVELOPMENT AND EXPLORATION ACTIVITIES.
The rate of production from crude oil and natural gas properties declines as
reserves are depleted. Our proved reserves will decline as reserves are produced
unless we acquire additional properties containing proved reserves, conduct
successful exploration, exploitation and development activities or, through
engineering studies, identify additional behind-pipe zones or secondary recovery
reserves. Our future crude oil and natural gas production is therefore highly
dependent upon our level of success in acquiring or finding additional reserves.
While we have had some success in pursuing these activities, we have not been
able to fully replace the production volumes lost from natural field declines
and property sales. We have implemented a number of measures to conserve our
cash resources, including postponement of exploration and development projects.
However, while these measures will conserve our cash resources in the near term,
they will also limit our ability to replenish our depleting reserves, which
could negatively impact our cash flow from operations in the future. The terms
of the new senior credit agreement and the notes limit our capital expenditures
which will further limit our ability to replenish our reserves and replace
production. Further, in addition to the effects of our limited liquidity, our
operations may be curtailed, delayed or cancelled by other factors, such as
title problems, weather, compliance with governmental regulations, mechanical
problems or shortages or delays in the delivery of equipment. We cannot assure
you that our exploration and development activities will result in increases in
reserves.
USE OF OUR NET OPERATING LOSS CARRYFORWARDS MAY BE LIMITED. At
December 31, 2002, Abraxas had, subject to the limitation discussed below,
$166.7 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, Abraxas 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 the financial
restructuring, certain of the loss carryforwards may be utilized.
As to a portion of the U.S. net operating loss carryforwards, the
amount of such carryforwards that we can use annually is limited under U.S. tax
law. Additionally, uncertainties exist as to the future utilization of the
operating loss carryforwards under the criteria set forth under FASB Statement
No. 109. Therefore, Abraxas has established a valuation allowance of
$39.7 million and $99.1 million for deferred tax assets at December 31, 2001 and
2002, respectively.
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CRUDE OIL AND NATURAL GAS PRICES AND THEIR VOLATILITY COULD ADVERSELY
AFFECT OUR REVENUE, CASH FLOWS, PROFITABILITY AND GROWTH. Our revenue, cash
flows, profitability and future rate of growth depend substantially upon
prevailing prices for crude oil and natural gas. Natural gas prices affect us
more than crude oil prices because most of our production and reserves are
natural gas. Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow money or raise additional capital. In
addition, we may have ceiling limitation write-downs when prices decline. During
the second quarter of 2002, we had a ceiling limitation write-down of
approximately $116.0 million. Lower prices may also reduce the amount of crude
oil and natural gas that we can produce economically.
We cannot predict future crude oil and natural gas prices. Factors
that can cause price fluctuations include:
- changes in supply and demand for crude oil and natural gas;
- weather conditions;
- the price and availability of alternative fuels;
- political and economic conditions in oil producing
countries, especially those in the Middle East; and
- overall economic conditions.
In addition to decreasing our revenue and cash flow from operations,
low or declining crude oil and natural gas prices could have additional material
adverse effects on us, such as:
- reducing the overall volumes of crude oil and natural gas
that we can produce economically;
- causing a ceiling limitation write-down;
- increasing our dependence on external sources of capital to
meet our liquidity requirements; and
- impairing our ability to obtain needed equity capital.
LOWER CRUDE OIL AND NATURAL GAS PRICES INCREASE THE RISK OF CEILING
LIMITATION WRITE-DOWNS. We use the full cost method to account for our crude oil
and natural gas operations. Accordingly, we capitalize the cost to acquire,
explore for and develop crude oil and natural gas properties. Under full cost
accounting rules, the net capitalized cost of crude oil and natural gas
properties may not exceed a "ceiling limit" which is based upon the present
value of estimated future net cash flows from proved reserves, discounted at
10%, plus the lower of cost or fair market value of unproved properties. If net
capitalized costs of crude oil and natural gas properties exceed the ceiling
limit, we must charge the amount of the excess to earnings. This is called a
"ceiling limitation write-down." This charge does not impact cash flow from
operating activities, but does reduce our stockholders' equity and earnings. The
risk that we will be required to write down the carrying value of crude oil and
natural gas properties increases when crude oil and natural gas prices are low.
In addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves. 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.
ESTIMATES OF OUR PROVED RESERVES AND FUTURE NET REVENUE ARE UNCERTAIN
AND INHERENTLY IMPRECISE. This prospectus contains estimates of our proved crude
oil and natural gas reserves and the estimated future net revenue from such
reserves. The process of estimating crude oil and natural gas reserves is
complex and involves decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data. Therefore, these
estimates are imprecise.
Actual future production, crude oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable crude oil and natural gas reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this prospectus. In
addition, we may adjust estimates of
18
<Page>
proved reserves to reflect production history, results of exploration and
development, prevailing crude oil and natural gas prices and other factors, many
of which are beyond our control.
You should not assume that the present value of future net revenues
referred to in this prospectus is the current market value of our estimated
crude oil and natural gas reserves. In accordance with SEC requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of the period of the estimate. Actual
future prices and costs may be materially higher or lower than the prices and
costs as of the end of the year of the estimate. Any changes in consumption by
natural gas purchasers or in governmental regulations or taxation will also
affect actual future net cash flows. The timing of both the production and the
expenses from the development and production of crude oil and natural gas
properties will affect the timing of actual future net cash flows from proved
reserves and their present value. In addition, the 10% discount factor, which is
required by the SEC to be used in calculating discounted future net cash flows
for reporting purposes, is not necessarily the most accurate discount factor.
The effective interest rate at various times and the risks associated with us or
the crude oil and natural gas industry in general will affect the accuracy of
the 10% discount factor.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of crude oil and natural gas reserves, future net
revenue from proved reserves and the PV-10 thereof for the crude oil and natural
gas properties described in this prospectus are based on the assumption that
future crude oil and natural gas prices remain the same as crude oil and natural
gas prices at December 31, 2002. The sales prices as of such date used for
purposes of such estimates were $29.69 per Bbl of crude oil, $18.89 per Bbl of
NGLs and $3.79 per Mcf of natural gas. This compares with $18.26 per Bbl of
crude oil, $16.29 per Bbl of NGLs and $2.16 per Mcf of natural gas as of
December 31, 2001. These estimates also assume that we will make future capital
expenditures of approximately $ 59.5 million in the aggregate, which are
necessary to develop and realize the value of proved undeveloped reserves on our
properties. Any significant variance in actual results from these assumptions
could also materially affect the estimated quantity and value of reserves set
forth herein.
WE HAVE EXPERIENCED RECURRING NET LOSSES. The following table shows
the losses we had in 1998, 1999, 2001 and 2002:
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
1998 1999 2001 2002
---- ---- ---- ----
Net (loss) $ (84.0) $ (36.7) $ (19.7) $ (118.5)
</Table>
While we had net income in 2000 of $8.4 million, if the significant gain on the
sale of an interest in a partnership were excluded, we would have experienced a
net loss for the year of $(25.5) million. We cannot assure you that we will
become profitable in the future.
THE MARKETABILITY OF OUR PRODUCTION DEPENDS LARGELY UPON THE
AVAILABILITY, PROXIMITY AND CAPACITY OF NATURAL GAS GATHERING SYSTEMS, PIPELINES
AND PROCESSING FACILITIES. The marketability of our production depends in part
upon processing facilities. Transportation space on such gathering systems and
pipelines is occasionally limited and at times unavailable due to repairs or
improvements being made to such facilities or due to such space being utilized
by other companies with priority transportation agreements. Our access to
transportation options can also be affected by U.S. federal and state and
Canadian regulation of crude oil and natural gas production and transportation,
general economic conditions, and changes in supply and demand. These factors and
the availability of markets are beyond our control. If market factors
dramatically change, the financial impact on us could be substantial and
adversely affect our ability to produce and market crude oil and natural gas.
OUR CANADIAN OPERATIONS ARE SUBJECT TO THE RISKS OF CURRENCY
FLUCTUATIONS AND IN SOME INSTANCES ECONOMIC AND POLITICAL DEVELOPMENTS. We
conduct operations in Canada. The expenses of such operations are payable in
Canadian dollars while most of the revenue from crude oil and natural gas sales
is based upon U.S. dollar price indices. As a result, Canadian operations are
subject to the risk of fluctuations in the relative values of the Canadian and
U.S. dollars. We are also required to recognize foreign currency
19
<Page>
translation gains or losses related to any debt issued by our Canadian
subsidiary because the debt is denominated in U.S. dollars and the functional
currency of such subsidiary is the Canadian dollar. Our foreign operations may
also be adversely affected by local political and economic developments, royalty
and tax increases and other foreign laws or policies, as well as U.S. policies
affecting trade, taxation and investment in other countries.
WE DEPEND ON OUR KEY PERSONNEL. We depend to a large extent on
Robert L.G. Watson, our Chairman of the Board, President and Chief Executive
Officer, for our management and business and financial contacts. The
unavailability of Mr. Watson could have a materially adverse effect on our
business. Mr. Watson has a three-year employment contract with Abraxas
commencing on December 21, 1999, which automatically renews thereafter for
successive one-year periods unless Abraxas gives 120 days notice prior to the
expiration of the original term or any extension thereof of its intention not to
renew the employment agreement. Our success is also dependent upon our ability
to employ and retain skilled technical personnel. While we have not experienced
difficulties in employing or retaining such personnel, our failure to do so in
the future could adversely affect our business.
RISKS RELATED TO OUR INDUSTRY
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF CRUDE OIL AND NATURAL
GAS DRILLING AND PRODUCTION ACTIVITIES. Our crude oil and natural gas drilling
and production activities are subject to numerous risks, many of which are
beyond our control. These risks include the following:
- that no commercially productive crude oil or natural gas
reservoirs will be found;
- that crude oil and natural gas drilling and production
activities may be shortened, delayed or canceled; and
- that our ability to develop, produce and market our reserves
may be limited by:
- title problems,
- weather conditions,
- compliance with governmental requirements, and
- mechanical difficulties or shortages or delays in the
delivery of drilling rigs, work boats and other
equipment.
In the past, we have had difficulty securing drilling equipment in
certain of our core areas. We cannot assure you that the new wells we drill will
be productive or that we will recover all or any portion of our investment.
Drilling for crude oil and natural gas may be unprofitable. Dry holes and wells
that are productive but do not produce sufficient net revenues after drilling,
operating and other costs are unprofitable. In addition, our properties may be
susceptible to hydrocarbon draining from production by other operations on
adjacent properties.
Our industry also experiences numerous operating risks. These
operating risks include the risk of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental hazards. Environmental hazards
include oil spills, natural gas leaks, ruptures or discharges of toxic gases. If
any of these industry operating risks occur, we could have substantial losses.
Substantial losses also may result from injury or loss of life, severe damage to
or destruction of property, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. In accordance with industry
practice, we maintain insurance against some, but not all, of the risks
described above. We cannot assure you that our insurance will be adequate to
cover losses or liabilities. Also, we cannot predict the continued availability
of insurance at premium levels that justify its purchase.
WE OPERATE IN A HIGHLY COMPETITIVE INDUSTRY WHICH MAY ADVERSELY AFFECT
OUR OPERATIONS. We operate in a highly competitive environment. Competition is
particularly intense with respect to the acquisition of desirable undeveloped
crude oil and natural gas properties. The principal competitive factors in the
acquisition of such undeveloped crude oil and natural gas properties include the
staff and data necessary to identify, investigate and purchase such properties,
and the financial resources necessary to acquire and develop such properties. We
compete with major and independent crude oil and natural gas
20
<Page>
companies for properties and the equipment and labor required to develop and
operate such properties. Many of these competitors have financial and other
resources substantially greater than ours.
The principal resources necessary for the exploration and production
of crude oil and natural gas are leasehold prospects under which crude oil and
natural gas reserves may be discovered, drilling rigs and related equipment to
explore for such reserves and knowledgeable personnel to conduct all phases of
crude oil and natural gas operations. We must compete for such resources with
both major crude oil and natural gas companies and independent operators.
Although we believe our current operating and financial resources are adequate
to preclude any significant disruption of our operations in the immediate
future, we cannot assure you that such materials and resources will be available
to us.
We face significant competition for obtaining additional natural gas
supplies for gathering and processing operations, for marketing NGLs, residue
gas, helium, condensate and sulfur, and for transporting natural gas and
liquids. Our principal competitors include major integrated oil companies and
their marketing affiliates and national and local gas gatherers, brokers,
marketers and distributors of varying sizes, financial resources and experience.
Certain competitors, such as major crude oil and natural gas companies, have
capital resources and control supplies of natural gas substantially greater than
ours. Smaller local distributors may enjoy a marketing advantage in their
immediate service areas.
OUR CRUDE OIL AND NATURAL GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S.
FEDERAL, STATE AND LOCAL AND CANADIAN FEDERAL AND PROVINCIAL GOVERNMENTAL
REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS. Matters regulated include
discharge permits for drilling operations, drilling and abandonment bonds,
reports concerning operations, the spacing of wells and unitization and pooling
of properties and taxation. At various times, regulatory agencies have imposed
price controls and limitations on production. In order to conserve supplies of
crude oil and natural gas, these agencies have restricted the rates of flow of
crude oil and natural gas wells below actual production capacity. Federal,
state, provincial and local laws regulate production, handling, storage,
transportation and disposal of crude oil and natural gas, by-products from crude
oil and natural gas and other substances and materials produced or used in
connection with crude oil and natural gas operations. To date, our expenditures
related to complying with these laws and for remediation of existing
environmental contamination have not been significant. We believe that we are in
substantial compliance with all applicable laws and regulations. However, the
requirements of such laws and regulations are frequently changed. We cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations.
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<Page>
USE OF PROCEEDS
We will not receive any proceeds from the sale of the notes or the
Abraxas common stock by the selling security holders pursuant to this
prospectus.
RATIO OF EARNINGS TO FIXED CHARGES
Earnings consist of income before income taxes plus fixed charges.
Fixed charges consist of interest expense, amortization of deferred financing
fees and premium on the old notes. Our earnings were inadequate to cover fixed
charges in 1998, 1999, 2001, 2002, and pro forma 2002, by $84.0 million, $36.7
million, $15.6 million, $148.2 million and $52.1 million, respectively. In 2000,
we had earnings of $46.7 million and fixed charges of $33.2 million. Our ratio
of earnings to fixed charges during 2000 was 1.41x. For the quarters ended
March 31, 2002 our earnings were inadequate to cover fixed charges by $9.5
million, for the quarter ended March 31,2003 we had earnings of $69.0 million
and fixed charges of $5.5 million. Our ratio of earnings to fixed charges for
March 31, 2003 was 12.5x.
CAPITALIZATION
The following table sets forth our cash position and total
consolidated capitalization at December 31, 2002, on a historical basis and
pro forma basis, and March 31, 2003, on a historical basis.
<Table>
<Caption>
December 31, 2002 March 31, 2003
----------------------------- --------------
Historical Pro Forma (1) Historical
------------ ------------- ------------
(dollars in thousands) (dollars in thousands)
Cash............................................................. $ 4,882 $ 557 $ 2,510
============ ============ ============
Total debt, including current maturities:
12 7/8% Senior Secured Notes due 2003 (first lien notes) 63,500 -- --
11 1/2% Senior Secured Notes due 2004 (second lien notes) 190,178 -- --
11 1/2% Senior Notes due 2004 (old notes)........................ 801 -- --
9 1/2% Senior Credit Facility ("Grey Wolf Facility")
providing for borrowing up to approximately US $96
million (CDN $150 million). Secured by the assets of
Old Grey Wolf and non-recourse to Abraxas...................... 45,964
New Senior Credit Agreement...................................... -- 46,700 45,137
11 1/2% Secured Notes due 2007 (new notes) (2)................... -- 128,600 128,598
------------ ------------ ------------
Total debt............................................... 300,443 175,300 173,735
Stockholders' equity (deficit)................................... (142,254) (73,158) (70,201)
------------ ------------ ------------
Total capitalization........................................... $ 158,189 $ 102,142 $ 103,534
============ ============ ============
</Table>
- ----------
(1) Reflects the exchange offer and each of the other transactions
described under "Business--Recent Developments--Financial
Restructuring."
(2) For financial reporting purposes, the new notes will be reflected at
the carrying value of the second lien notes and old notes prior to the
exchange of $191.0 million, net of the cash offered in the exchange of
$47.5 million and net of the fair market value related to equity of
$3.8 million offered in the exchange. In conjunction with the
financial restructuring transaction, Abraxas paid cash of
$11.5 million ($11.1 million in principal and $0.4 million in
interest) to redeem certain of the outstanding old notes, and
second lien notes and accrued interest. The result of all of these
items will be a remaining carrying value of the new notes of
$128.6 million. At March 31, 2003, the face amount of the new notes
was $109.7 million.
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<Page>
PRICE RANGE OF ABRAXAS COMMON STOCK
Abraxas common stock began trading on the American Stock Exchange on
August 18, 2000 under the symbol "ABP." The following table sets forth certain
information as to the high and low bid quotations quoted for Abraxas' common
stock on the American Stock Exchange.
<Table>
<Caption>
PERIOD HIGH LOW
------ ---- ---
2001 First Quarter................................... $ 5.32 $ 3.69
Second Quarter.................................. 4.98 3.10
Third Quarter................................... 3.65 1.70
Fourth Quarter.................................. 1.85 0.88
2002
First Quarter................................... $ 1.70 $ 0.89
Second Quarter.................................. 1.41 0.52
Third Quarter................................... 0.98 0.42
Fourth Quarter.................................. 0.80 0.52
2003
First Quarter................................... $ 0.99 $ 0.55
Second Quarter.................................. 1.40 0.50
Third Quarter (through July 29, 2003).......... 1.11 0.80
</Table>
DIVIDENDS
Abraxas has not paid any cash dividends on its common stock and it is
not presently determinable when, if ever, Abraxas will pay cash dividends in the
future. In addition, the senior credit facility and the indenture governing the
notes prohibit the payment of cash dividends and stock dividends on Abraxas'
common stock. You should read the discussion under "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--" beginning on page 37 for more information regarding the
restrictions on Abraxas' ability to pay dividends.
23
<Page>
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Unaudited Pro Forma Statements of Operations of Abraxas for the
year ended December 31, 2002 has been prepared assuming the divestiture of
the East White Point Field and the repurchase of a production payment which
occurred in the second quarter of 2002, and the sale of Canadian Abraxas and
Old Grey Wolf, which occurred in January 2003, (collectively, the "Sale of
Properties") and the exchange offer and each of the other transactions
described under "Business--Recent Developments--Financial Restructuring" had
occurred on January 1, 2002. The Unaudited Pro Forma Condensed Consolidated
Statements of Operations of Abraxas for the three months ended March 31, 2003
has been prepared assuming that the exchange offer and each of the other
transactions described under "Business--Recent Developments--Financial
Restructuring" had occurred on January 1, 2002. The pro forma financial data
are based on assumptions and include adjustments as explained in the notes to
the Unaudited Pro Forma Condensed Consolidated Financial Statements. The
unaudited pro forma financial statements are not necessarily indicative of
results that actually would have been achieved had the exchange offer and
each of the other referenced transactions been consummated on the dates
indicated or that may be achieved in the future.
These unaudited pro forma condensed consolidated financial statements
have been prepared from, and should be read along with, "Management's Discussion
and Analysis of Financial Condition and Results of Operations", "Selected
Historical Financial Data", our Consolidated Financial Statements and the notes
thereto included elsewhere in this prospectus.
24
<Page>
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2003
<Table>
<Caption>
HISTORICAL
ABRAXAS
PETROLEUM SALE OF FINANCIAL
CORPORATION PROPERTIES (1) RESTRUCTURING PRO FORMA
-------------- -------------- -------------- --------------
Revenues:
Oil and gas production revenues............ $ 12,772 $ (3,119) $ -- $ 9,653
Gas processing revenue..................... 132 (132) -- --
Rig revenues............................... 181 -- -- 181
Other...................................... 26 (24) -- 2
-------------- -------------- -------------- --------------
Total revenues...................... 13,111 (3,275) -- 9,836
Operating costs and expenses:
Lease operating and production taxes 2,726 (379) -- 2,347
Depreciation, depletion and amortization... 3,142 (792) -- 2,350
Rig operations............................. 166 -- 166
General and administrative................. 1,395 (165) -- 1,230
General and administrative (stock-based
compensation)............................ 36 -- 36
-------------- -------------- -------------- --------------
Total operating expenses............ 7,465 (1,336) -- 6,129
-------------- -------------- -------------- --------------
Operating income (loss)...................... 5,646 (1,939) -- 3,707
Other (income) expense:
Interest income............................ (10) -- -- (10)
Amortization of deferred financing fees.... 377 (48) 105(2) 434
Interest expense........................... 5,164 (641) 867(3) 5,390
Financing costs............................ 3,601 -- (3,601)(4) -
Gain of sale of foreign subsidiaries....... (66,960) 66,960 -- -
-------------- -------------- -------------- --------------
Income (loss) before cumulative effect of
accounting change and taxes .......... 63,474 (68,210) 2,629 (2,107)
Cumulative effect of accounting change ...... (395) -- -- (395)
-------------- -------------- -------------- --------------
Earnings (loss) before tax .................. 63,079 (68,210) 2,629 (2,502)
Income tax expense .......................... 377 (377) -- --
-------------- -------------- -------------- --------------
Net loss .................................... 62,702 (67,833) 2,629 (2,502)
============== ============== ============== ==============
Weighted average common shares:
Basic ................................... 34,181,118 34,181,118
-------------- --------------
Diluted ................................. 34,500,590 34,500,590
-------------- --------------
Loss per common share:
Basic ................................... $ 1.83 $ (0.29)
============== ==============
Diluted ................................. $ 1.82 $ (0.29)
============== ==============
</Table>
See notes to unaudited pro forma financial statements.
25
<Page>
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2002
<Table>
<Caption>
HISTORICAL
ABRAXAS
PETROLEUM SALE OF FINANCIAL
CORPORATION PROPERTIES RESTRUCTURING PRO FORMA
-------------- -------------- -------------- --------------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues:
Oil and gas production revenues............ $ 50,862 $ (30,327)(1) $ $ 20,535
Gas processing revenue..................... 2,420 (2,420) -- --
Rig revenues............................... 635 -- -- 635
Other...................................... 403 (332) -- 71
-------------- -------------- -------------- --------------
Total revenues...................... 54,320 (33,079) -- 21,241
Operating costs and expenses:
Lease operating and production taxes....... 15,240 (7,543)(1) -- 7,697
Depreciation, depletion and amortization... 26,539 (17,688)(1) 8,851
Proved property impairment................. 115,993 (83,143) -- 32,850
Rig operations............................. 567 -- -- 567
General and administrative................. 6,884 (1,802) -- 5,082
-------------- -------------- -------------- --------------
Total operating expenses............ 165,223 (110,176) -- 55,047
-------------- -------------- -------------- --------------
Operating income (loss)...................... (110,903) 77,097 -- (33,806)
Other (income) expense:
Interest income............................ (92) -- -- (92)
Amortization of deferred (1,325)(3)
financing fees........................... 2,095 (770) 1,724(3) 1,724
Interest expense........................... (33,546)(3)
34,150 (604)(2) 15,500(3) 15,500
Financing costs............................ 967 -- -- 967
Other...................................... 201 -- -- 201
-------------- -------------- -------------- --------------
Income (loss) from before income tax (148,224) 78,471 17,647 (52,106)
Income tax expense (benefit):................ (29,697) 29,697 -- --
-------------- -------------- -------------- --------------
Net loss.................................. $ (118,527) $ 48,774 $ 17,647 $ (52,106)
============== ============== ============== ==============
Weighted average common shares:
Basic.................................... 29,979,397 5,642,699(4) 35,622,096
-------------- -------------- --------------
Diluted.................................. 29,979,397 5,642,699(4) 35,622,096
-------------- -------------- --------------
Loss from per common share - basic
and diluted: $ (3.95) $ (1.46)
</Table>
See notes to unaudited pro forma financial statements.
26
<Page>
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2002
<Table>
<Caption>
HISTORICAL
ABRAXAS
PETROLEUM SALE OF FINANCIAL
CORPORATION PROPERTIES (1) RESTRUCTURING PRO FORMA
------------ ------------ ------------ ------------
Assets:
Cash.......................................................... $ 4,882 $ (4,325) $ -- $ 557
Accounts receivable........................................... 10,045 (4,016) -- 6,029
Other......................................................... 2,254 (917) -- 1,337
------------ ------------ ------------ ------------
Total current assets...................................... 17,181 (9,258) -- 7,923
Net property and equipment...................................... 150,394 (54,468) 95,926
Deferred financing fees......................................... 5,671 (2,701) 2,465(5) 5,435
Other assets.................................................... 8,179 (7,820) -- 359
------------ ------------ ------------ ------------
Total assets.............................................. $ 181,425 $ (74,247) $ 2,465 $ 109,643
============ ============ ============ ============
Liabilities and Stockholders' Equity (Deficit):
Current Liabilities:
Accounts payable.............................................. $ 12,119 $ (6,311) -- 5,808
Current maturities of First Lien Notes........................ 63,500 -- (63,500)(2) --
Other current liabilities..................................... 7,171 (1,009) (5,000)(2) 1,162
------------ ------------ ------------ ------------
Total current liabilities................................. 82,790 (7,320) (68,500) 6,970
Long-term debt:
New Secured Notes............................................. -- 128,598(6) 128,598
Senior Credit Agreement....................................... -- 46,700(4) 46,700
Old Notes..................................................... 801 -- (801)(5) --
Second Lien Notes............................................. 190,178 -- (190,178)(5) --
Grey Wolf credit facility..................................... 45,964 (45,964) -- --
------------ ------------ ------------ ------------
Total..................................................... 236,943 (45,964) (15,681) 175,298
Deferred income taxes........................................... -- -- --
Other liabilities............................................... 3,946 (3,413) -- 533
Stockholders' equity (deficit):
Common stock.................................................. 301 -- 56(3) 357
Additional paid-in capital.................................... 136,830 -- 3,724(3) 140,554
Receivable from stock sale.................................... (97) -- -- (97)
Accumulated deficit........................................... (269,621) (17,550) 78,289(7) (208,882)
Accumulated other comprehensive income........................ (8,703) -- 4,577(1) (4,126)
Treasury stock................................................ (964) -- -- (964)
------------ ------------ ------------ ------------
Total stockholders' equity (deficit)...................... (142,254) (17,550) 86,646 (73,158)
------------ ------------ ------------ ------------
Total liabilities and stockholders' equity (deficit)...... $ 181,425 $ (74,247) $ 2,465 $ 109,643
============ ============ ============ ============
</Table>
See notes to unaudited pro forma financial statements.
27
<Page>
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Notes to the Unaudited Pro Forma Condensed Consolidated Statements of
Operations:
THREE MONTHS ENDED MARCH 31, 2003:
(1) To adjust oil and gas production revenues, lease operating and
production taxes and depreciation, depletion and amortization as if
the Canadian properties, sold in connection with the sale of Canadian
Abraxas and Old Grey Wolf which occurred in the first quarter of
2003, had been completed as of January 1, 2002.
(2) To adjust amortization of deferred financing fees for additional fees
paid in connection with new credit agreement, and to amortize balance
of fees associated with exchanged notes over the life of the new
notes.
(3) To adjust interest expense on long-term debt at the stated interest
rates of the associated debt. Interest expense on the new debt
includes cash interest expense on the new revolving credit facility
and non-cash (additional notes) interest expense on the term loan and
the new secured notes. Non cash interest expense is calculated at 9%
on the term loan and at an imputed rate of 8.6% on the new notes based
on the carrying value of the exchanged notes of $128.6 million.
(4) To eliminate nonrecurring charges attributable to the financing
transactions.
YEAR ENDED DECEMBER 31, 2002:
(1) To adjust oil and gas production revenues, lease operating and
production taxes and depreciation, depletion and amortization as if
the East White Point property sale and the repayment of a production
payment obligation which occurred in the second quarter of 2002 had
been completed as of January 1, 2002.
(2) To adjust interest expense, giving effect to pay-down of Abraxas'
long-term debt and current maturities of long-term debt, at the stated
interest rates of the associated debt.
(3) To adjust the amortization of deferred financing fees for debt retired
and record the amortization of additional fees related to the new
senior credit agreement. To adjust interest expense to reflect debt
retired and record expense on new debt. Interest expense on the new
debt includes cash interest expense on the new revolving credit
facility and non-cash (additional notes) interest expense on the term
loan and the new secured notes. Non cash interest expense is
calculated at 9% on the term loan and at an imputed rate of 8.6% on
the new notes based on the carrying value of the exchanged notes of
$128.6 million. See note 5 to the unaudited pro forma condensed
consolidated balance sheet for the calculation of the carrying value
of the new notes. Additionally, in connection with the exchange offer,
Abraxas incurred expenses of $3.8 million of non-recurring cost which
are not reflected in these pro forma financial statements.
(4) To reflect the issuance of approximately 5.64 million shares of common
stock as part of the financial restructuring.
Notes to the Unaudited Pro Forma Condensed Consolidated Balance Sheet:
(1) To adjust the balance sheet for disposal of Canadian operations, as of
December 31, 2002.
(2) To adjust the balance sheet for the retirement of the existing first
lien notes and payment of accrued interest.
(3) To adjust the balance sheet for the issuance of approximately 5.64
million shares of common stock as part of the financial restructuring
at a market price of $0.67.
(4) To adjust the balance sheet for borrowings under the new senior credit
agreement.
(5) To adjust the balance sheet for the restructuring of the second lien
notes and old notes, to recognize $2.5 million in financing fees which
were incurred in connection with the new senior credit agreement.
(6) For financial reporting purposes, the new notes are reflected on the
books at the carrying value of the second lien notes and old notes
prior to the exchange ($191.0 million), net of the cash offered in the
exchange ($47.5 million) and net of the fair market value related to
equity ($3.8 million) offered in the exchange. In conjunction with
this transaction, Abraxas paid cash of $11.5 million ($11.1 million in
principal and $0.4 million in interest) to redeem certain of the
outstanding notes and accrued interest. The result of all of these
items is a remaining carrying value of the new notes of $128.6
million.
(7) To adjust the accumulated deficit for the estimated gain on the sale
of Canadian operations. Net proceeds of the sale of the common stock
of Old Grey Wolf and Canadian Abraxas were $132.1 million reduced by
the
28
<Page>
book value of the assets sold ($67.8 million) and accrued interest and
debt discount on the Old Grey Wolf credit facility retired ($3.6
million).
SELECTED HISTORICAL FINANCIAL DATA
The following historical selected consolidated financial data are
derived from our Consolidated Financial Statements and the notes thereto
included elsewhere in this prospectus. The Statement of Operations Data for the
three months ended March 31, 2003, is not necessarily indicative of results of a
full year. The consolidated financial data for the three months ended March 31,
2002 and March 31, 2003 are derived from our unaudited financial statements and,
in the opinion of management, include all adjustments that are of a normal and a
recurring nature and necessary for a full presentation. Separate financial
statements for Old Grey Wolf, as of December 31, 2001 and 2002 and for the years
ended December 31, 2000, 2001 and 2002 are included elsewhere in this
prospectus. The selected historical consolidated financial information should be
read in conjunction with our Consolidated Financial Statements and the notes
thereto and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" included elsewhere in this prospectus. As discussed in
Note 20 to the consolidated financial statements, the Company's financial
statements have been restated.
<Table>
<Caption>
THREE MONTHS ENDED
------------------
YEAR ENDED DECEMBER 31, MARCH 31,
----------------------- ---------
1998 1999 2000 2001 2002 2002 2003
---------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
CONSOLIDATED STATEMENTS OF
OPERATIONS DATA:
Operating revenue:
Oil and gas production revenues....... $ 54,263 $ 59,025 $ 72,973 $ 73,201 $ 50,862 $ 10,886 $ 12,772
Gas processing revenue................ 3,159 4,244 2,717 2,438 2,420 670 132
Rig and other revenue................. 2,662 3,501 910 1,604 1,038 251 207
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenue.......... 60,084 66,770 76,600 77,243 54,320 11,807 13,111
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating costs and expenses:
Lease operating and production taxes.... 18,091 17,938 18,783 18,616 15,240 3,909 2,726
Depreciation, depletion and
amortization expense.................. 31,226 34,811 35,857 32,484 26,539 6,814 3,142
General and administrative expense...... 5,522 5,269 6,533 6,445 6,884 1,698 1,395
General and administrative (Stock-based
compensation)......................... -- -- 2,767 (2,767) -- -- 36
Other................................... 521 624 717 702 567 121 166
Proved property impairment.............. 61,224 19,100 -- 2,638 115,993 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating expenses......... 116,584 77,742 64,657 58,118 165,223 12,542 7,465
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income (loss)................. (56,500) (10,972) 11,943 19,125 (110,903) (735) 5,646
Net interest expense.................... 30,043 36,149 30,610 31,445 34,058 8,380 5,154
Amortization of deferred financing
Fees................................ 1,571 1,915 2,091 2,268 2,095 427 377
Financing cost.......................... -- -- -- -- 967 -- 3,601
Gain on debt extinguishment............. -- -- (1,773) -- -- -- --
(Gain) loss on sale of equity
investment............................ -- -- (33,983) 845 -- -- --
Gain on sale of foreign subsidiaries.... -- -- -- -- -- -- (66,960)
Other (income) expense.................. 4 -- 1,563 207 201 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) before taxes and
cumulative effect of accounting
change............................... (88,118) (49,036) 13,435 (15,640) (148,224) (9,542) 63,474
Cumulative effect of accounting change.. -- -- -- -- -- -- (395)
Income tax (expense) benefit............ 4,158 12,625 (3,705) (2,402) 29,697 843 (377)
Minority interest in (income) loss of
consolidated foreign subsidiaries..... -- (269) (1,281) (1,676) -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss)........................... $ (83,960) $ (36,680) $ 8,449 $ (19,718) $ (118,527) $ (8,699) $ 62,702
========== ========== ========== ========== ========== ========== ==========
Income (loss) from per common share:
Basic................................. $ (13.26) $ (5.41) $ 0.29 $ (0.76) $ (3.95) $ (0.29) $ 1.83
Diluted............................... (13.26) (5.41) 0.21 (0.76) (3.95) (0.29) 1.82
CONSOLIDATED BALANCE SHEET DATA:
Total assets............................ $ 291,498 $ 322,284 $ 335,560 $ 303,616 $ 181,425 $ 309,294 $ 117,647
Long-term debt - excluding current
maturities............................ 299,698 273,421 266,441 262,240 236,943 227,103 173,735
</Table>
29
<Page>
<Table>
Stockholder's equity (deficit).......... (63,522) (9,505) (6,503) (28,585) (142,254) (39,726) (70,201)
</Table>
30
<Page>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion of our consolidated 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.
As discussed in Note 20 to the consolidated financial statements, the
Company's financial statements have been restated. The following management's
discussion and analysis gives effect to that restatement.
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. During
2002, crude oil and natural gas prices began to increase from 2001 levels and
increased further in the first quarter of 2003. In addition, because 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 reserves and
production will decrease. 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. In order to
provide us with liquidity and capital resources, we have sold certain of our
producing properties. However, our production levels have declined as we have
been unable to replace the production represented by the properties we have sold
with new production from the producing properties we have invested in with the
proceeds of our property sales. In addition, 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 flow from operations and financial condition will be materially
adversely affected. For more information, see "--Liquidity and Capital
Resources--" and "--Future Capital Resources."
RESULTS OF OPERATIONS
GENERAL. Our financial results depend upon many factors, particularly
the following factors which most significantly affect our results of operations:
- the sales prices of crude oil, natural gas liquids and
natural gas;
- the level of total sales volumes of crude oil, natural gas
liquids and natural gas;
- the ability to raise capital resources and provide liquidity
to meet cash flow needs;
- the level of and interest rates on borrowings; and
- 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. 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 to increase during the first
part of 2003. In the first quarter of 2003, we experienced an increase in energy
commodity prices from the prices that we received in the first quarter of 2002.
The table below illustrates how natural gas prices fluctuated over the
nine quarters prior to and including the quarter ended March 31, 2003. The table
below also contains the last three day average of
31
<Page>
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)
<Table>
<Caption>
Quarter Ended
-----------------------------------------------------------------------------------------------------------------
March 31, June 30, Sept. Dec.31, March 31, June 30, Sept. 30, Dec. 31, March 31,
2001 2001 30, 2001 2001 2002 2002 2002 2002 2003
---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------
Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 $ 2.38 $ 3.36 $ 3.28 $ 3.99 $ 6.61
Realized 4.85 3.41 2.26 2.09 2.21 2.44 2.08 3.47 5.13
</Table>
The NYMEX natural gas price on May 8, 2003 was $5.77 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.
CRUDE OIL PRICES BY QUARTER (IN $ PER BBL)
<Table>
<Caption>
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31, March 31,
2001 2001 2001 2001 2002 2002 2002 2002 2003
---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------
Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48 $ 26.40 $ 27.50 $ 28.29 $ 33.71
Realized 27.22 25.32 25.06 18.72 16.64 23.47 23.47 24.83 33.22
</Table>
The NYMEX crude oil price on May 8, 2003 was $26.98 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 quarter of 2002 we experienced hedging losses of
$250,000. 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, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our crude oil and natural gas production for a rolling six month 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 agreement, for the calendar
months of February through July 2003. In February 2003, we entered into a second
hedge agreement for the calendar months of March 2003 through February 2004,
related to 5,000 MMBtu, which provides for a floor price of $4.50 per MMBtu.
During the first quarter of 2003, we incurred hedging losses of $470,890 in
connection with our collar option agreement.
SELECTED OPERATING DATA. The following table sets forth certain of our
operating data for the periods presented.
<Table>
<Caption>
THREE MONTHS
ENDED MARCH 31,
YEARS ENDED DECEMBER 31, (UNAUDITED)
----------------------------------------------------------------------
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT DATA)
2000 2001 2002 2002 2003
----------------------------------------------------------------------
Operating revenue:
Crude oil sales*............................ $ 11,899 $ 11,184 $ 7,114 $ 1,232 $ 2,174
NGLs sales.................................. 7,061 5,979 4,343 872 511
Natural gas sales*.......................... 54,013 56,038 39,405 8,782 10,087
Gas processing revenue...................... 2,717 2,438 2,420 670 132
Rig and other............................... 910 1,604 1,038 251 207
----------------------------------------------------------------------
Total operating revenues.................... $ 76,600 $ 77,243 $ 54,320 $ 11,807 $ 13,111
======================================================================
</Table>
32
<Page>
<Table>
Operating income (loss)..................... $ 11,943 $ 19,125 $ (110,903) $ (735) $ 5,646
Crude oil production (MBbls)................ 636.7 454.1 292.3 74.0 65.4
NGLs production (MBbls)..................... 314.9 278.0 242.0 68.4 20.2
Natural gas production (MMcf)............... 19,962.5 17,495.6 15,452.7 3,973.1 1,965.3
Average crude oil sales price (per Bbl)* $ 18.69 $ 24.63 $ 24.34 $ 16.64 $ 33.22
Average NGLs sales price (per Bbl) $ 22.42 $ 21.51 $ 17.94 $ 12.76 $ 25.29
Average natural gas sales price (per Mcf)* $ 2.71 $ 3.20 $ 2.55 $ 2.21 $ 5.13
</Table>
*Revenue and average sales prices are net hedging activities.
COMPARISON OF THREE MONTHS ENDED MARCH 31, 2003 TO THREE MONTHS ENDED MARCH 31,
2002
OPERATING REVENUE. During the three months ended March 31, 2003, operating
revenue from crude oil, natural gas and natural gas liquid sales increased to
$12.8 million compared to $10.9 million in the three months ended March 31,
2002. The increase in revenue was primarily due to increased prices realized
during the period, partially offset by a decline in production volumes. Higher
commodity prices impacted crude oil and natural gas revenue by $7.2 million
while reduced production volumes had a $5.6 million negative impact on revenue.
Average sales prices net of hedging losses for the quarter ended March 31, 2003
were:
- - $33.22 per Bbl of crude oil,
- - $25.29 per Bbl of natural gas liquid, and
- - $ 5.13 per Mcf of natural gas
Average sales prices net of hedging losses for the quarter ended March 31, 2002
were:
- - $16.64 per Bbl of crude oil,
- - $12.76 per Bbl of natural gas liquid, and
- - $ 2.21 per Mcf of natural gas
Crude oil production volumes declined by 8.6 MBbls from 74.0 MBbls during the
quarter ended March 31, 2002 to 65.4 MBbls for the same period of 2003. The
decline in crude oil production was primarily due to the sale of U.S. properties
in the second quarter of 2002. These properties contributed 4.9 MBbls of crude
oil in the first quarter of 2002. Additionally, the Canadian properties sold in
January 2003 in connection with the sale of Canadian Abraxas and Old Grey Wolf
contributed 6.4 MBbls during the quarter ended March 2002 compared to 2.4 MBbls
during the quarter ended March 2003 (through January 23, 2003). Natural gas
production volumes declined by 2,007.8 MMcf to 1,965.3 MMcf for the three months
ended March 31, 2003 from 3,973.1 MMcf for the same period of 2002. This decline
was primarily due to the sale of U.S. properties in the second quarter of 2002.
These properties contributed 152.2 MMcf for the quarter ended March 31, 2002.
The decrease in production applicable to the properties which were sold was
offset by new production from drilling activities which contributed 4.5 MBbls of
crude oil and 225.4 MMcf of natural gas during the first quarter of 2003.
LEASE OPERATING EXPENSES. Lease operating expenses ("LOE") for the three
months ended March 31, 2003 increased to $2.7 million from $3.9 million for the
same period in 2002. The decrease in LOE was primarily due to the sale of
Canadian Abraxas and Old Grey Wolf in January 2003. LOE related to the
properties sold was $2.0 million for the first quarter of 2002 compared to
$379,000 during the first quarter of 2003 through the date of the sale.
Partially offsetting the decline was an increase in production tax expense due
to higher commodity prices in the quarter ended March 31, 2003 compared to the
same period of 2002. LOE on a per Mcfe basis for the three months ended March
31, 2003 was $1.10 per Mcfe compared to $0.81 for the same period of 2002. The
increase in the per Mcfe expense was primarily due to
33
<Page>
the increase in production tax expense described above and by a decline in
production volumes in the first quarter of 2003 compared to the same period in
2002.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSES. G&A expenses decreased by $0.3
million to $1.4 million during the quarter ended March 31, 2003 for the first
three months of 2003 from $1.7 million for the first three months of 2002. G&A
expense on a per Mcfe basis was $0.56 for the first quarter of 2003 compared to
$0.33 for the same period of 2002. 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. The increase in G&A expense on a per Mcfe
basis was primarily due to a decline in production volumes during the first
quarter of 2003 compared to the same period in 2002.
G&A 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 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 approximately $36,000 as stock-based compensation expense during the
quarter ended March 31, 2003 related to these repricings. During 2002, we did
not recognize any stock -based compensation due to the decline in the price of
our common stock.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES. Depreciation, depletion
and amortization ("DD&A") expense decreased slightly to $3.1 million for the
three months ended March 31, 2003 from $6.8 million for the same period of 2002.
The decline in DD&A was primarily due to the sale of Canadian properties 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 three months ended March 31, 2003 was
$1.27 per Mcfe compared to $1.41 in 2002.
INTEREST EXPENSE. Interest expense decreased from $8.4 million for the
first three months of 2002 to $5.2 million in 2003. The decrease in interest
expense was due to the reduction in long-term debt in the first quarter of 2003
as compared to the same period of 2002. The reduction in debt was the result of
the financial transactions which occurred on January 23, 2003 as described in
Note 3 in the Notes to Consolidated Financial Statements.
COMPARISON OF YEAR ENDED DECEMBER 31, 2002 TO YEAR ENDED DECEMBER 31, 2001
OPERATING REVENUE. During the year ended December 31, 2002, operating
revenue from crude oil, natural gas and natural gas liquids sales decreased by
$22.3 million from $73.2 million in 2001 to $50.9 million in 2002. This decrease
was primarily attributable to a decrease in production volumes and lower
commodity prices in 2002 as compared to 2001. Crude oil and natural gas revenue
was impacted by $11.5 million from a decline in commodity prices and $10.8
million from reduced production. The decline in production was due to the
disposition of certain properties in south Texas and natural field declines.
Natural gas liquids volumes declined from 278.0 MBbls in 2001 to 242.0
MBbls in 2002. Crude oil sales volumes declined from 454.1 MBbls in 2001 to
292.3 MBbls during 2002. Natural gas sales volumes decreased from 17.5 Bcf in
2001 to 15.5 Bcf in 2002. Production declines were primarily attributable to our
disposition of assets during 2002 and natural field declines.
Average sales prices in 2002 net of hedging losses were:
- $ 24.34 per Bbl of crude oil,
- $ 17.94 per Bbl of natural gas liquids, and
- $ 2.55 per Mcf of natural gas.
34
<Page>
Average sales prices in 2001 net of hedging losses were:
- $24.63 per Bbl of crude oil,
- $21.51 per Bbl of natural gas liquids, and
- $ 3.20 per Mcf of natural gas.
LEASE OPERATING EXPENSE. Lease operating expense ("LOE") decreased
from $18.6 million in 2001 to $15.2 million in 2002. LOE on a per Mcfe basis for
2002 was $0.82 per Mcfe as compared to $0.83 per Mcfe in 2001. The decrease in
the per Mcfe cost is due to a reduced operating cost offset by the decline in
production volumes.
G&A EXPENSE. General and administrative ("G&A") expense increased
slightly from $6.4 million in 2001 to $6.9 million in 2002. This increase was
due primarily to increased legal expenses related to ongoing litigation in 2002.
Our G&A expense on a per Mcfe basis increased from $0.30 in 2001 to $0.37 in
2002. The increase in the per Mcfe cost was due primarily to lower production
volumes in 2002 as compared to 2001.
G&A - STOCK-BASED COMPENSATION EXPENSE. 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 subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. We charged approximately
$2.8 million to stock-based compensation expense in 2000 compared to crediting
approximately $2.8 million in 2001. This was due to the decline in the market
price of our common stock during 2001. During 2002, we did not recognize any
stock-based compensation due to the decline in the price of our common stock.
DD&A EXPENSE. Depreciation, depletion and amortization ("DD&A")
expense decreased by $5.9 million from $32.4 million in 2001 to $26.5 million in
2002. The decline in DD&A is due to reductions in our full cost pool resulting
from ceiling test write-downs, as well as lower production volumes. Our DD&A
expense on a per Mcfe basis for 2002 was $1.42 per Mcfe as compared to $1.74 per
Mcfe in 2001.
INTEREST EXPENSE. Interest expense increased from $31.5 million to
$34.1 million for 2002 compared to 2001. The increase was the result of
additional sales pursuant to our production payment arrangement with Mirant
Americas as well as increased borrowings under Old Grey Wolf's credit facility
in 2002. The production payment was reacquired in June 2002 for approximately
$6.8 million.
CEILING LIMITATION WRITE-DOWN. We record the carrying value of our
crude oil and natural gas properties using the full cost method of accounting.
For more information on the full cost method of accounting, you should read the
description under "--Critical Accounting Policies--Full Cost Method of
Accounting for Crude Oil and Natural Gas Activities". As of December 31, 2001,
our net capitalized costs of crude oil and natural gas properties exceeded the
present value of its estimated proved reserves by $71.3 million. These amounts
were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil
and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized
prices for each of the full cost pools. We did not adjust our capitalized costs
for its U.S. properties because subsequent to December 31, 2001, crude oil and
natural gas prices increased such that capitalized costs for its U.S. properties
did not exceed the present value of the estimated proved crude oil and natural
gas reserves for its U.S. properties as determined using increased realized
prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for
natural gas
At 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). These amounts were calculated considering June 30, 2002 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. Subsequent
to June 30, 2002, commodity prices increased in Canada and we utilized these
increased prices in calculating the ceiling limitation write-down. The total
write-down
35
<Page>
was approximately $116.0 million. At December 31, 2002 our net capitalized cost
of crude oil and natural gas properties did not exceed the present value of our
estimated reserves, due to increased commodity prices during the fourth quarter
and, as such, no further write-down was recorded. We cannot assure you that we
will not experience additional ceiling limitation write-downs in the future.
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. We cannot assure you that we will not
experience additional write-downs in the future. If commodity prices decline or
if any of our proved resources are revised downward, a further write-down of the
carrying value of our crude oil and natural gas properties may be required. See
Note 18 of Notes to Consolidated Financial Statements.
INCOME TAXES. Income tax expense decreased from an expense of $2.4
million for the year ended December 31, 2001 to a benefit of $29.7 million for
the year ended December 31, 2002. The decrease was primarily due to the tax
benefit relating to the ceiling limitation write-down related to our Canadian
properties.
COMPARISON OF YEAR ENDED DECEMBER 31, 2001 TO YEAR ENDED DECEMBER 31, 2000
OPERATING REVENUE. During the year ended December 31, 2001, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$200,000 from $73.0 million in 2000 to $73.2 million in 2001. This increase was
primarily attributable to an increase in commodity prices offset by a decline in
production volumes. Increased prices contributed $12.9 million in additional
revenue, which was offset by $12.7 million due to a decrease in production
volumes. The decline in production was due to the disposition of certain
properties and natural field declines.
Natural gas liquids volumes declined from 314.9 MBbls in 2000 to 278.0
MBbls in 2001. Crude oil sales volumes declined from 636.7 MBbls in 2000 to
454.1 MBbls during 2001. Natural gas sales volumes decreased from 20.0 Bcf in
2000 to 17.5 Bcf in 2001. Production declines were primarily attributable to our
property disposition and natural field declines. Average sales prices in 2001
net of hedging losses were:
- $ 24.63 per Bbl of crude oil,
- $ 21.51 per Bbl of natural gas liquids, and
- $ 3.20 per Mcf of natural gas.
Average sales prices in 2000 net of hedging losses were:
- $18.69 per Bbl of crude oil,
- $22.42 per Bbl of natural gas liquids, and
- $ 2.71 per Mcf of natural gas.
LEASE OPERATING EXPENSE. Lease operating expense decreased from $18.8
million in 2000 to $18.6 million in 2001. LOE on a per Mcfe basis for 2001 was
$0.85 per Mcfe as compared to $0.73 per Mcfe in 2000. The increase in the per
Mcfe cost is due to a decline in production volumes.
G&A EXPENSE. General and administrative expense decreased from $6.5
million in 2000 to $6.4 million in 2001. Our G&A expense on a per Mcfe basis
increased from $0.27 in 2000 to $0.29 in 2001. The increase in the per Mcfe cost
was due primarily to lower production volumes in 2001 as compared to 2000.
G&A - STOCK-BASED COMPENSATION EXPENSE. 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
36
<Page>
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. We charged approximately
$2.8 million to stock-based compensation expense in 2000 compared to crediting
approximately $2.8 million in 2001. This was due to the decline in the market
price of our common stock during 2001.
DD&A EXPENSE. Depreciation, depletion and amortization expense
decreased by $3.4 million from $35.9 million in 2000 to $32.5 million in 2001.
Our DD&A expense on a per Mcfe basis for 2001 was $1.48 per Mcfe as compared to
$1.40 per Mcfe in 2000. The decline in DD&A is due to reductions in our full
cost pool resulting from ceiling test write-downs in prior years, as well as
lower production volumes.
INTEREST EXPENSE. Interest expense increased by $400,000 from $31.1
million to $31.5 million for 2001 compared to 2000. This increase resulted from
an increase in debt levels during 2001 compared to 2000. The increase in our
debt level was the result of additional sales pursuant to our production payment
arrangement with Mirant Americas.
CEILING LIMITATION WRITE-DOWN. 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. As of December 31, 2001, our net
capitalized costs of crude oil and natural gas properties exceeded the present
value of estimated proved reserves by $71.3 million ($38.9 million on the U.S.
properties and $32.4 million on the Canadian properties). These amounts were
calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and
$2.57 per Mcf for natural gas as adjusted to reflect the expected realized
prices for each of the full cost pools. We did not adjust capitalized costs for
U.S. properties because subsequent to December 31, 2001, crude oil and natural
gas prices increased such that capitalized costs for U.S. properties did not
exceed the present value of the estimated proved crude oil and natural gas
reserves for U.S. properties as determined using increased realized prices on
March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural
gas.
INCOME TAXES. Income tax expense decreased from $3.7 million for the
year ended December 31, 2000 to $2.4 million for the year ended December 31,
2001. Income taxes for the year ended December 31, 2000 related to deferred
taxes on the sale of the Wamsutter partnership.
OTHER. In March 2000, Abraxas Wamsutter L.P. ("Partnership") sold all
of its interest in its crude oil and natural gas properties to a third party.
Prior to the sale of these properties, effective January 1, 2000, our equity
investee share of crude oil and natural gas property cost, results of operations
and amortization were not material to consolidated operations or financial
position. As a result of the sale, we received approximately $34 million, which
represented a proportional interest in the Partnership's proved properties.
In June 2000, we retired $3.5 million of the old notes and $3.6
million of the second lien notes at a discount of $1.8 million.
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:
- the development of existing properties, including drilling
and completion costs of wells;
- acquisition of interests in crude oil and natural gas
properties; and
- 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.
37
<Page>
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 March 31, 2003, our current liabilities of
approximately $12.9 million exceeded our current assets of $11.0 million
resulting in a working capital deficit of $1.9 million. This compares to a
working capital deficit of approximately $65.7 million at December 31, 2002.
However, as a result of the financial restructuring completed in January 2003,
our current liabilities were significantly reduced. Current liabilities at March
31, 2003 consisted of trade payables of $5.2 million, revenues due third parties
of $2.5 million and accrued interest of $2.5 million related to our new notes,
which was paid on May 1 with the issuance of additional notes. 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 in 2000, 2001 and 2002 and
for the three months ended March 31, 2003 were $39.8 million, $19.1 million,
$15.9 million and $4.4 million, respectively. The table below sets forth the
components of these capital expenditures for for the three years ended
December 31, 2000, 2001 and 2002 and for the three months ended March 31, 2002
and 2003.
<Table>
<Caption>
Year Ended December 31, Three Months Ended March 31,
-----------------------------------------------------------------
2000 2001 2002 2003 2002
-----------------------------------------------------------------
(dollars in thousands)
Expenditure category:
Property acquisitions $ 7,189 $ - $ - $ - $ -
Development 64,873 56,694 38,560 4,423 17,249
Facilities and other 2,350 362 154 166 131
---------- --------- --------- ---------- ----------
$ 74,412 $ 57,056 $ 38,714 $ 4,589 $ 17,408
========== ========== ========== ========== ==========
</Table>
During the three months ended March 31, 2003 and 2002 and during 2000,
2001 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 agreement and new notes,
including a maximum annual capital expenditure budget of $15 million for 2003,
which is subject to reduction in the event of a reduction in our net assets. 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
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<Page>
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:
<Table>
<Caption>
Three Months Ended
Year Ended December 31, March 31,
--------------------------- ----------------------
2000 2001 2002 2003 2002
---------- ---------- ---------- --------- ----------
Net cash (used in) provided by operating activities $ 21,372 $ 16,263 $ (8,336) $ 2,745 $ 8,282
Net cash provided by (used in) investing activities (18,773) (30,797) (5,036) 81,235 (17,408)
Net cash provided by (used in) financing activities (3,818) 20,685 10,836 (86,587) 5,377
--------------------------------------------------------------
Total $ (1,219) $ 6,151 $ (2,536) $ (2,607) $ (3,749)
==============================================================
</Table>
Operating activities during the three months ended March 31, 2003 provided
us $2.7 million cash compared to providing $8.3 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. Operating
activities for the year ended December 31, 2002, used $8.3 million of cash.
Investing activities used $5.0 million during 2002. Our investing activities
included the sale of properties which provided $33.9 million, and the use of
$38.9 million primarily for the development of producing properties. Financing
activities used $79.3 million for the first three months of 2003 compared to
using $698,000 for the same period of 2002. Most of these funds used were to
reduce our long-term debt and were generated by the sale of our Canadian
subsidiaries and the exchange offer completed in January 2003. Financing
activities provided us with $10.8 million during 2002, relating primarily to
advances on Old Grey Wolf's Credit Facility.
Operating activities for the year ended December 31, 2001, provided us
$16.3 million of cash. Investing activities included the sale of properties
which provided $28.9 million, and the use of $57.1 million for the development
of producing properties and $2.7 million for the acquisition of the minority
interest in Grey Wolf.. Financing activities provided $20.7 million during 2001,
including the provision of additional funding of $11.7 million under our
production payment arrangement with Mirant Americas, and the provision of $18.3
million under Old Grey Wolf's credit facility. Payments on long term debt used
$9.3 million during 2001.
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 indenture and the new senior credit agreement
substantially restrict our ability to:
- incur additional indebtedness;
- incur liens;
- pay dividends or make certain other restricted payments;
- consummate certain asset sales;
- enter into certain transactions with affiliates;
- merge or consolidate with any other person; or
39
<Page>
- sell, assign, transfer, lease, convey or otherwise dispose
of all or substantially all of our assets.
We believe that our best opportunity for additional sources of liquidity and
capital will be through the issuance of equity securities or through the
disposition of assets as allowed under the various financing arrangements.
CONTRACTUAL OBLIGATIONS
We are committed to making cash payments in the future on the following
types of agreements:
- Long-term debt
- 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
March 31, 2003:
<Table>
<Caption>
Payments due in:
- ---------------------------------------------------------------------------------------------------
Contractual Obligations Less than More than
(dollars in thousands) Total one year 1-3 years 3-5 years 5 years
- ---------------------------------------------------------------------------------------------------
Long-Term Debt (1) $ 230,638 $ - $ 46,394 $ 184,244 -
Operating Leases (2) 1,545 351 929 265 -
</Table>
- ----------
(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 thereunder.
(2) Office lease obligations. Leases for office space for Abraxas and New
Grey Wolf expire in April 2006 and December 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.
LONG-TERM INDEBTEDNESS. The recently completed financial restructuring
resulted in the retirement of our first lien notes, second lien notes and old
notes, together with the Old Grey Wolf credit facility. As of March 31, 2003,
our long-term indebtedness consists of the new senior credit facility and the
new notes issued in connection with the financial restructuring. The following
table sets forth our long-term indebtedness as of December 31, 2002, and
March 31, 2003 and pro forma information at December 31, 2002 reflecting the
consummation of the restructuring transactions.
LONG-TERM INDEBTEDNESS
<Table>
<Caption>
---------------------------------------------------
PRO FORMA
DECEMBER 31,
2002
AFTER
DECEMBER 31, 2002 RESTRUCTURING(1) MARCH 31, 2003
---------------------------------------------------
12 7/8% Senior Secured Notes due 2003 (first lien notes)...... $ 63,500 $ - $
11 1/2% Senior Secured Notes due 2004 (second lien notes)..... 190,178 -
11 1/2% Senior Notes due 2004 (old notes)..................... 801 -
</Table>
40
<Page>
<Table>
9 1/2% Senior Credit Facility ("Old Grey Wolf Facility")
providing for borrowings up to approximately US $96
million (CDN $150 million). Secured by the assets of
Old Grey Wolf and non-recourse to Abraxas..................... 45,964 - -
Production Payment .......................................... - - -
11 1/2% Secured Notes due 2007 (new notes) - January 2003..... - 128,600 128,598
New Senior Credit Agreement - January 2003.................... - 46,700 45,137
---------------------------------------------------
300,443 175,300 173,735
Less current maturities ...................................... 63,500 - -
---------------------------------------------------
$ 236,943 $ 175,300 $ 173,735
===================================================
</Table>
(1) For financial reporting purposes, the new notes will be reflected at
the carrying value of the second lien notes and old notes prior to the
exchange of $191.0 million, net of the cash offered in the exchange of
$47.5 million and net of the fair market value related to equity of
$3.8 million offered in the exchange. In conjunction with the
financial restructuring transaction, Abraxas paid cash of $11.5
million ($11.1 in principal and $0.4 million in interest) to redeem
certain of the outstanding old debt and accrued interest. The result
of all of these items will be a remaining carrying value of the new
notes of $128.6 million. The face amount of the new notes is $109.7
million.
11 1/2% SECURED NOTES. In connection with the financial restructuring,
Abraxas issued $109.7 million in principal amount of 11 1/2% Secured Notes due
2007, Series A, in exchange for the second lien notes and old notes tendered in
the exchange offer. The notes were issued under an indenture with U.S. Bank,
N. A. For a more complete description of the notes, see "Description of the
Notes" beginning on page 81 of this prospectus.
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. Upon closing of the financial restructuring, we
borrowed $4.2 million pursuant to a term loan facility, 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 $49.9 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. 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 March 31, 2003, the outstanding balance was $40.9 million under
the revolving credit facility. We plan to use the remaining borrowing
availability under the new senior credit agreement to fund our operations,
including capital expenditures.
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 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
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<Page>
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:
- incur additional indebtedness;
- create or permit to be created any liens on any of our
properties;
- enter into any change of control transactions;
- dispose of our assets;
- change our name or the nature of our business;
- make any guarantees with respect to the obligations of third
parties;
- enter into any forward sales contracts;
- make any payments in connection with distributions,
dividends or redemptions relating to our outstanding
securities, or
- 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 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 and all future
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.
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 calendar months of February through July
2003. In February 2003, we entered into a second hedge agreement related to
5,000 MMBtu, for the calendar months of March 2003 through February 2004 which
provides for a floor price of $4.50 per MMBtu. See "--Quantitative and
Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further
information.
NET OPERATING LOSS CARRYFORWARDS
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<Page>
At December 31, 2002 we had, subject to the limitation discussed
below, $166.7 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, we 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 financial restructuring
transactions described in Note 3, in Notes to Consolidated Financial Statements,
certain of the loss carryforwards may be utilized.
As a result of the acquisition of certain partnership interests and
crude oil and natural gas properties in 1990 and 1991, an ownership change under
Section 382 occurred in December 1991. Accordingly, it is expected that the use
of the U.S. net operating loss carryforwards generated prior to December 31,
1991 of $3,203,000 will be limited to approximately $235,000 per year.
During 1992, we acquired 100% of the common stock of an unrelated
corporation. The use of net operating loss carryforwards of the acquired
corporation of $257,000 acquired in the acquisition are limited to approximately
$115,000 per year.
As a result of the issuance of additional shares of common stock for
acquisitions and sales of common stock, an additional ownership change under
Section 382 occurred in October 1993. Accordingly, it is expected that the use
of all U.S. net operating loss carryforwards generated through October 1993
(including those subject to the 1991 and 1992 ownership changes discussed above)
of $6,590,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999,
following the issuance of additional shares, as described in Note 6. It is
expected that the annual use of U.S. net operating loss carryforwards subject to
this Section 382 limitation will be limited to approximately $363,000, subject
to the lower limitations described above. Future changes in ownership may
further limit the use of our carryforwards. In 2000 assets with built-in gains
were sold, increasing the Section 382 limitation for 2001 by approximately
$31,000,000.
The annual Section 382 limitation may be increased during any year,
within 5 years of a change in ownership, in which built-in gains that existed on
the date of the change in ownership are recognized.
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, we have established a
valuation allowance of $39.7 million and $99.1 million for deferred tax assets
at December 31, 2001 and 2002, respectively.
43
<Page>
OUTLOOK FOR 2003
We have previously communicated the following guidance for 2003:
<Table>
Production:
BCFE (approximately 80% gas) 7 - 8
Price differentials (Pre Hedge):
$ per Bbl of oil 0.64
$ per Mcf of natural gas 0.51
LOE, $ per MCFE 1.21
G&A, $ per MCFE 0.69
Capital Expenditures ($ millions) 15.0
</Table>
Actual results could materially differ and will depend on, among other
things, our ability to successfully increase our production of crude oil,
natural gas liquids and natural gas through our drilling activities. We
undertake no duty to update these forward-looking statements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
As an independent crude oil and natural gas producer, our revenue, cash
flow from operations, other income and profitability, reserve values, access to
capital and future rate of growth are substantially dependent upon the
prevailing prices of crude oil, natural gas and natural gas liquids. Declines in
commodity prices will materially adversely affect our financial condition,
liquidity, ability to obtain financing and operating results. Lower commodity
prices may reduce the amount of crude oil and natural gas that we can produce
economically. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control, such as global political and
economic conditions. Historically, prices received for crude oil and natural gas
production have been volatile and unpredictable, and such volatility is expected
to continue. Most of our production is sold at market prices. Generally, if the
commodity indexes fall, the price that we receive for our production will also
decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. Assuming the production levels we
attained during the year ended December 31, 2002 a 10% decline in crude oil,
natural gas and natural gas liquids prices would have reduced our operating
revenue, cash flow and net income by approximately $5.1 million for the year.
HEDGING SENSITIVITY
On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and
SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. If the derivative does not qualify as a hedge or is not
designated as a hedge, the gain or loss on the derivative is recognized
currently in earnings. To qualify for hedge accounting, the derivative must
qualify either as a fair value hedge, cash flow hedge or foreign currency hedge.
Currently, we use only cash flow hedges and the remaining discussion will relate
exclusively to this type of derivative instrument. If the derivative qualifies
for hedge accounting, the gain or loss on the derivative is deferred in Other
Comprehensive Income (Loss), a component of Stockholders' Equity, to the extent
that the hedge is effective.
The relationship between the hedging instrument and the hedged item
must be highly effective in achieving the offset of changes in cash flows
attributable to the hedged risk both at the inception of the contract and on an
ongoing basis. Hedge accounting is discontinued prospectively when a hedge
instrument
44
<Page>
becomes ineffective. Gains and losses deferred in accumulated Other
Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective,
remain unchanged until the related production is delivered. If we determine that
it is probable that a hedged transaction will not occur, deferred gains or
losses on the hedging instrument are recognized in earnings immediately.
Gains and losses on hedging instruments related to Accumulated other
comprehensive income 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. In 2000, 2001 and 2002, we experienced
hedging losses of $20.2 million, $12.1 million and $3.2 million, respectively.
In October 2002, all of these hedge agreements expired. Under the expired hedge
agreements, we made total payments to various counterparties in the amount of
$35.1 million.
Under the terms of the new senior credit agreement, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our crude oil and natural gas production for a rolling six month 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. In February of 2003 we
entered into an additional hedge agreement for 5,000 MMBtu per day with a floor
of $4.50 per MMBtu. For Abraxas, the fair value of the hedging instrument was
determined based on the base price of the hedged item and NYMEX forward price
quotes.
The following table sets forth the Company's hedge position as of
March 31, 2003:
<Table>
<Caption>
Time Period Notional Quantities Price Fair Value
- ------------------------------------- ------------------------------ ------------------------------ ----------------
February 1, 2003--July 31, 2003 5,000 MMBtu of production Collar with floor of $4.00 $ -
per day and ceiling of $6.25
March 1, 2003 - February 29, 2004 5,000 MMBtu of production Floor of $4.50 $ 361,769
per day
</Table>
All hedge transactions are subject to our risk management policy,
which has been approved by the Board of Directors. We formally document all
relationships between hedging instruments and hedged items, as well as our 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.
INTEREST RATE RISK
At December 31, 2002, substantially all of Abraxas' long-term debt was
at fixed interest rates from 11.5% to 12.875% and not subject to fluctuations in
market rates and Old Grey Wolf's long-term debt was at a fixed interest rate of
9.5%.
As of March 31, 2003, we had approximately $45.1 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 1.5%) 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 $451,000 on an annual basis. Our notes accrue interest at a fixed
rate and, accordingly, are 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 $304,000 for the quarter ended March 31,
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 $15,000.
Canadian operations reported a pre-tax loss of $63.4
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<Page>
million for the year ended December 31, 2002. It is estimated that a 5% change
in the value of the U.S. dollar to the Canadian dollar would have changed our
net loss by approximately $3.2 million. 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.
RELATED PARTY TRANSACTIONS
Accounts receivable - Other in the consolidated balances sheets includes
approximately $48,365 and $51,211 as of December 31, 2001 and 2002,
respectively, representing amounts due from officers and stockholders relating
to advances made to employees.
Wind River Resources Corporation ("Wind River"), all of the capital
stock of which is owned by the Company's President, previously owned a
twin-engine airplane. The airplane was available for business use by the
employees of the Company from time to time. The Company paid Wind River a
total of approximately $336,000, $314,000 and $345,000 in 2000, 2001 and 2002
respectively, for Wind River's operating costs associated with the Company's
use of the plane. The airplane was sold in July 2003.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
FULL COST METHOD OF ACCOUNTING FOR CRUDE OIL AND NATURAL GAS
ACTIVITIES. SEC Regulation S-X defines the financial accounting and reporting
standards for companies engaged in crude oil and natural gas activities. Two
methods are prescribed: the successful efforts method and the full cost method.
Abraxas has chosen to follow the full cost method under which all costs
associated with property acquisition, exploration and development are
capitalized. We also capitalize internal costs that can be directly identified
with our acquisition, exploration and development activities and do not include
any costs related to production, general corporate overhead or similar
activities. Under the successful efforts method, geological and geophysical
costs and costs of carrying and retaining undeveloped properties are charged to
expense as incurred. Costs of drilling exploratory wells that do not result in
proved reserves are charged to expense. Depreciation, depletion, amortization
and impairment of crude oil and natural gas properties are generally calculated
on a well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of crude oil and
natural gas properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher depreciation, depletion and amortization date on our
crude oil and natural gas properties.
At the time it was adopted, management believed that the full cost
method would be preferable, as earnings tend to be less volatile than under the
successful efforts method. However, the full cost method makes us susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
recoverable when prices return to higher levels. We have experienced this
situation several times over the years, most recently in 2002. Our crude oil and
natural gas reserves have a relatively long life. However, temporary drops in
commodity prices can have a material impact on our business including impact
from the full cost method of accounting.
Under full cost accounting rules, the net capitalized cost of crude
oil and natural gas properties may not exceed a "ceiling limit" which is based
upon the present value of estimated future net cash flows from proved reserves,
discounted at 10%, plus the lower of cost or fair market value of unproved
properties. If net capitalized costs of crude oil and natural gas properties
exceed the ceiling limit, we must charge the amount of the excess to earnings.
This is called a "ceiling limitation write-down." This charge does not impact
cash flow from operating activities, but does reduce our stockholders' equity
and reported earnings. The risk that we will be required to write down the
carrying value of crude oil and natural gas
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properties increases when crude oil and natural gas prices are depressed or
volatile. In addition, write-downs may occur if we experience substantial
downward adjustments to our estimated proved reserves or if purchasers cancel
long-term contracts for our natural gas production. 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.
For the year ended December 31, 2002, we recorded a write-down of
$116.0 million. The write-down in 2002 was due to low commodity prices. We
cannot assure you that we will not experience additional write-downs in the
future. Should commodity prices decline, a further write-down of the carrying
value of our crude oil and natural gas properties may be required.
ESTIMATES OF PROVED OIL AND NATURAL GAS RESERVES. Estimates of our
proved reserves included in this prospectus are prepared in accordance with GAAP
and SEC guidelines. The accuracy of a reserve estimate is a function of:
- the quality and quantity of available data;
- the interpretation of that data;
- the accuracy of various mandated economic assumptions;
- and the judgment of the persons preparing the estimate.
Our proved reserve information included in this prospectus was based
on evaluations prepared by independent petroleum engineers. Estimates prepared
by other third parties may be higher or lower than those included herein.
Because these estimates depend on many assumptions, all of which may
substantially differ from future actual results, reserve estimates will be
different from the quantities of oil and gas that are ultimately recovered. In
addition, results of drilling, testing and production after the date of an
estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows
is the current market value of our estimated proved reserves. In accordance with
SEC requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If
the estimates of proved reserves decline, the rate at which we record DD&A
expense will increase, reducing future net income. Such a decline may result
from lower market prices, which may make it uneconomic to drill for and produce
higher cost fields.
HEDGE ACCOUNTING. From time to time, we use commodity price hedges to
limit our exposure to fluctuations in crude oil and natural gas prices. Results
of those hedging transactions are reflected in crude oil and natural gas sales.
Statement of Financial Accounting Standards, ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities", was effective
for us on January 1, 2001. SFAS 133, as amended and interpreted, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Under this statement, all derivatives, whether designated in hedging
relationships or not, are required to be recorded at fair value on our balance
sheet. The accounting for changes in the fair value of a derivative instrument
depends on the intended use of the derivative and the resulting designation,
which is established at the inception of a derivative. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results of the hedged item in the consolidated statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. For derivative instruments
designated as fair value hedges, changes in fair value, to the extent the hedge
is effective, are recognized as an increase or decrease to the value of the
hedged item until the hedged item is recognized in earnings. Hedge effectiveness
is measured at least quarterly based on the relative changes in fair value
between the derivative contract and the hedged item over time. Any change in the
fair value resulting from
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ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.
Changes in fair value of contracts that do not meet the SFAS 133 definition of a
cash flow or fair value hedge are also recognized in earnings through risk
management income. All amounts initially recorded in this caption are ultimately
reversed within the same caption and included in oil and gas sales or interest
expense, as applicable, over the respective contract terms.
One of the primary factors that can have an impact on our results of
operations is the method used to value our derivatives. We have established the
fair value of all derivative instruments using estimates determined by our
counterparties and subsequently evaluated internally using established index
prices and other sources. These values are based upon, among other things,
futures prices, volatility, time to maturity and credit risk. The values we
report in our financial statements change as these estimates are revised to
reflect actual results, changes in market conditions or other factors, many of
which are beyond our control.
Another factor that can impact our results of operations each period
is our ability to estimate the level of correlation between future changes in
the fair value of the hedge instruments and the transactions being hedged, both
at the inception and on an ongoing basis. This correlation is complicated
because energy commodity prices, the primary risk we hedge, have quality and
location differences that can be difficult to hedge effectively. The factors
underlying our estimates of fair value and our assessment of correlation of our
hedging derivatives are impacted by actual results and changes in conditions
that affect these factors, many of which are beyond our control.
Due to the volatility of crude oil and natural gas prices and, to a
lesser extent, interest rates, our financial condition and results of operations
can be significantly impacted by changes in the market value of our derivative
instruments. As of December 31, 2001 the net market value of our derivatives was
a liability of $658,000. As of December 31, 2002 we did not have any outstanding
derivatives.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the purchase method of
accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. Intangible assets with a determinable
useful life will continue to be amortized over that period. The amortization
provisions apply to goodwill and intangible assets acquired after June 30, 2001.
SFAS No. 141 and 142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did not change or
reclassify contractual mineral rights included in oil and gas properties on the
balance sheet upon adoption of SFAS No. 142. The Company believes the treatment
of such mineral rights as tangible assets under the full cost method of
accounting for crude oil and natural gas properties is appropriate. An issue has
arisen regarding whether contractual mineral rights should be classified as
intangible rather that tangible assets. If it is determined that
reclassification is necessary, the Company's oil and gas properties would be
reduced by $868,000 and $3.1 million and intangible assets would have increased
by a like amount at December 31, 2001 and 2002, respectively, representing cost
incurred from the effective date of June 30, 2001. The provisions of SFAS No.
141 and 142 impact only the balance sheet and associated footnote disclosure,
and reclassifications necessary would not impact the Company's cash flows or
results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 is effective for us January 1,
2003. SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortize these costs as a component of our depletion
expense.
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We have completed our assessment of SFAS No. 143 and based on our
estimates, we do not expect the statement to have a material effect on our
financial position, results of operations and cash flows for future periods. At
January 1, 2003, we estimate that the present value of our future Asset
Retirement Obligation ("ARO") for natural gas and oil property and related
equipment is approximately $657,000. We estimate that the cumulative effect to
the adoption of SFAS No. 143 and the change in the accounting principle will be
a loss of $285,000, which will be recorded in the first quarter of 2003. The
impact on each of the prior years was not material. Effective January 1, 2002,
we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." SFAS No. 144 retains the requirement to recognize an
impairment loss only where the carrying value of a long-lived asset is not
recoverable from its undiscounted cash flows and to measure such loss as the
difference between the carrying amount and fair value of the asset. SFAS No.
144, among other things, changes the criteria that have to be met to classify an
asset as held-for-sale and requires that operating losses from discontinued
operations be recognized in the period that the losses are incurred rather than
as of the measurement date. This new standard had no impact on the consolidated
financial statements for the year ended December 31, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No.
4, 44, and 64, Amendments of FASB Statement No. 13 and Technical Corrections."
SFAS No. 145 clarifies guidance related to the reporting of gains and losses
from extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS No. 145 also amends
other existing pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed conditions. The
provisions relating to the reporting of gains and losses from extinguishment of
debt become effective for us beginning January 1, 2003. All other provisions of
this standard were effective for us as of May 15, 2002 and did not have an
impact on our financial condition or results of operations. Upon issuance of our
restated financial statements which are included in this Form S-1, Amendment No.
2, we have reclassified the gain on the early extinguishment of debt in 2000
from an extraordinary item to other income - see Note 20. This reclassification
did not affect net income for the year ended December 31, 2000.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. SFAS
No. 146 is effective for us beginning January 1, 2003. For the period ended
March 31, 2003 this standard had no impact on the Company's financial condition
or results of operation.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-based Compensation--Transition and Disclosure, an amendment of FASB
Statement No. 123," which amends SFAS No. 123 to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. It also amends the disclosure provisions
of SFAS No. 123 to require prominent disclosure in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. The
provisions of SFAS No. 148 are effective for annual financial statements for
fiscal years ending after December 15, 2002, and for financial reports
containing condensed financial statements for interim periods beginning after
December 15, 2002. We will continue to use APB No. 25 to account for stock based
compensation while providing the disclosures required by SFAS No. 123 as amended
by SFAS No. 148.
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BUSINESS
GENERAL
We are an independent energy company engaged primarily in the
acquisition, exploration, exploitation, and production of crude oil and natural
gas. Our principal means of growth has been through the acquisition and
subsequent development and exploitation of producing properties. As a result of
our historical acquisition activities, we believe that we have a substantial
inventory of low risk exploration and development opportunities, the development
of which is critical to the maintenance and growth of our current production
levels. We seek to complement our acquisition and development activities by
selectively participating in exploration projects with experienced industry
partners.
Our principal areas of operation are Texas and western Canada. At
December 31, 2002, we owned interests in 548,819 gross acres (422,874 net
acres), and operated properties accounting for approximately 88% of our PV-10,
affording us substantial control over the timing and incurrence of operating and
capital expenditures. At December 31, 2002 estimated total proved reserves were
166.5 Bcfe with an aggregate PV-10 of $254.9 million. Subsequent to the
transactions described in "Recent Events" our reserves were reduced by 54.0 Bcfe
with an aggregate PV-10 of $118.3 million.
BUSINESS STRATEGY
Our primary business objectives are to increase reserves, production
and cash flow through the following:
- LOW COST OPERATIONS. We seek to maintain low lease operating
and G&A expenses per Mcfe by operating a majority of our
producing properties and by maintaining a high rate of
production on a per well basis. As a result of this
strategy, we have achieved per unit lease operating and G&A
expenses that compare favorably with our peer companies.
- EXPLOITATION OF EXISTING PROPERTIES. We will continue to
allocate a portion of our operating cash flow to the
exploitation of our proved oil and natural gas properties.
We believe that the proximity of our undeveloped reserves to
existing production makes development of these properties
less risky and more cost-effective than other drilling
opportunities available to us. Given our high degree of
operating control, the timing and incurrence of operating
and capital expenditures is largely within our discretion.
Abraxas' inventory of development opportunities is
considerable and growing, but our ability to exploit that
inventory will depend on our ability to raise additional
capital and on our discretionary cash flow, which in turn is
highly dependent on future crude oil and natural gas prices.
RECENT DEVELOPMENTS
FINANCIAL RESTRUCTURING
We recently completed a series of transactions designed to reduce our
indebtedness, improve our ability to meet our debt service obligations and
provide us with working capital necessary to develop our existing crude oil and
natural gas properties. As a result of these transactions, which we sometimes
refer to in this prospectus as the financial restructuring, we have reduced the
principal amount of our overall outstanding long-term debt from approximately
$300 million at December 31, 2002 to approximately $156.4 million in principal
amount at January 23, 2003, and have reduced our annual cash interest payments
from approximately $34 million, to approximately $4 million, assuming that, as
required under the new senior credit agreement, Abraxas issues additional notes
in lieu of cash interest payments. After giving effect to the financial
restructuring on January 23, 2003, the principal amount of our outstanding
indebtedness as of March 31, 2003 was approximately $156.4 million ($109.7
million in outstanding notes and $46.7 million related to the new senior credit
agreement). Due to the accounting treatment under accounting principles
generally accepted in the United States of America for financial restructurings,
the reported carrying value of such total indebtedness will be approximately
$175 million ($128.6 million
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related to the outstanding notes). The transactions comprising the financial
restructuring are summarized below.
EXCHANGE OFFER. On January 23, 2003 Abraxas 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, or second lien
notes, and 11 1/2% Senior Notes due 2004, Series D, or old notes, issued by
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
notes tendered in the exchange offer, tendering note holders received:
- cash in the amount of $264;
- an 11 1/2% Secured Note due 2007, Series A, with a principal
amount equal to $610; and
- 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately
$190.2 million of the second lien notes and $801,000 of the old notes
outstanding. 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
historical 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, for approximately $11.5
million ($11.1 million in principal and $0.4 million in interest). The
indentures for the second lien notes and old notes were duly discharged. In
connection with the exchange offer, Abraxas made cash payments of approximately
$47.5 million and issued approximately $109.7 million in principal amount of
notes and 5,642,699 shares of Abraxas common stock, each of which are being
offered for resale under this prospectus. Fees and expenses incurred in
connection with the exchange offer were approximately $3.8 million.
SALE OF STOCK OF CANADIAN ABRAXAS AND OLD GREY WOLF. Contemporaneously
with the closing of the exchange offer, on January 23, 2003, Abraxas completed
the sale to a wholly-owned subsidiary of PrimeWest Energy Inc. of all of the
outstanding capital stock of two of Abraxas' former wholly owned subsidiaries,
Canadian Abraxas and Old Grey Wolf for approximately $138 million before net
adjustments of $3.4 million. The aggregate sales price for the shares of capital
stock of Canadian Abraxas and Old Grey Wolf was as follows:
<Table>
<Caption>
Number of Shares Sales Price
---------------- -----------
Canadian Abraxas 5,751 common shares $68 million
Old Grey Wolf 12,804,628 common shares $70 million
------------
TOTAL SALES PRICE: $138 million
------------
</Table>
After sales price adjustments and related costs and expenses of
approximately $5.9 million were made, the sales price realized for the sale of
Canadian Abraxas and Old Grey Wolf was $132.1 million. Upon consummation of the
sale, Old Grey Wolf repaid the outstanding indebtedness under its credit
agreement with Mirant Canada Energy Capital, Ltd. in the amount of $46.3
million, which reduced the net proceeds from the sale by a corresponding amount.
The net cash proceeds from the sale were $85.8 million, all of which has been
utilized in connection with the financial restructuring.
The properties transferred in conjunction with the sale of Canadian
Abraxas and Old Grey Wolf amounted to approximately 35% of our total proved
reserves at June 30, 2002 and approximately 60% of our production for the
quarter ended September 30, 2002. Under the terms of the agreement with
PrimeWest, Abraxas has retained certain assets formerly held by Canadian Abraxas
and Old Grey Wolf, including all of Canadian Abraxas' and Old Grey Wolf's
undeveloped acreage existing at the time of the sale, which includes all of our
interests in the Ladyfern area. These assets have been contributed to New Grey
Wolf, a new wholly-owned Canadian subsidiary of Abraxas. Portions of this
undeveloped acreage will be developed by PrimeWest and New Grey Wolf under a
farmout arrangement. Under the farmout arrangements, PrimeWest has agreed to
participate in the development of certain lands of New Grey Wolf
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in the Caroline and Pouce Coupe areas of Alberta. PrimeWest has the right to
obtain a 60% interest in certain wells if it bears 100% of the expense of
drilling such wells. In addition, New Grey Wolf and PrimeWest will have an
area of mutual interest in respect of the lands surrounding the Caroline area
where each party will be entitled to participate in the acquisitions of the
other, with New Grey Wolf participating with a 40% interest and PrimeWest
participating with a 60% interest.
REDEMPTION OF FIRST LIEN NOTES. On January 24, 2003, we completed the
redemption of 100% of our outstanding 12 7/8% Senior Secured Notes, Series A, or
first lien notes, with approximately $66.4 million of the proceeds from the sale
of Canadian Abraxas and Old Grey Wolf. Prior to the redemption, we had $63.5
million of our first lien notes outstanding. Under the terms of the indenture
for the first lien notes, as of March 15, 2002, we had the right to redeem the
first lien notes at 100% of the outstanding principal amount of the notes, plus
accrued and unpaid interest to the date of redemption, and to discharge the
indenture upon call of the first lien notes for redemption and deposit of the
redemption funds with the trustee. We exercised these rights on January 23, 2003
and upon the discharge of the indenture, the trustee released the collateral
securing our obligations under the first lien notes.
NEW SENIOR CREDIT AGREEMENT. Contemporaneously with the closing of the
exchange offer and the sale of Canadian Abraxas and Old Grey Wolf, on
January 23, 2003, Abraxas entered into a new senior credit agreement providing a
term loan facility of $4.2 million and a revolving credit facility with a
maximum borrowing base of up to $50 million. For a detailed description of the
credit facilities under the new senior credit agreement, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Long-Term Indebtedness" beginning
on page 41.
SOURCES AND USES OF FUNDS IN FINANCIAL RESTRUCTURING
The following table illustrates the sources and uses of funds for the
financial restructuring.
<Table>
<Caption>
SOURCES OF FUNDS
----------------
(US DOLLARS IN MILLIONS)
Sale of Canadian Abraxas and
Old Grey Wolf (1)......................... $ 132.1
New Senior Credit Agreement (2)........... 46.7
--------
Total Sources............................. $ 178.8
========
<Caption>
USES OF FUNDS
-------------
Redemption of First Lien Notes (3)........ $ 66.4
Exchange Offer Cash Payments (4).......... 59.0
Repayment of Old Grey Wolf
Credit Facility (5)....................... 46.3
Fees and Expenses......................... 7.1
--------
Total Uses................................ $ 178.8
========
</Table>
- ----------
(1) Represents CDN $205.9 million converted to US $134.6 million at an
exchange rate of US $0.6538 per CDN $1.00, less fees and expenses of
$2.5 million.
(2) Includes term loan facility of $4.2 million and outstanding amounts
under the revolving credit facility of $42.5 million at the time of
the financial restructuring.
(3) Represents $63.5 million in principal amount of the first lien notes
and accrued interest of $2.9 million.
(4) Represents payments of $47.5 million for the cash portion of the
exchange offer consideration and payments of $11.5 million for the
redemption of the second lien notes and old notes remaining
outstanding upon closing of the exchange offer.
(5) Represents CDN $70.8 million converted to US $46.3 million at an
exchange rate of US $0.6538 per CDN $1.00.
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2002 ASSET SALES
In May 2002, our former wholly-owned Canadian subsidiaries, Old Grey
Wolf and Canadian Abraxas, sold their interest in a natural gas processing plant
and associated crude oil and natural gas reserves in the Quirk Creek and Mahaska
fields in Alberta, Canada for approximately $22.9 million.
In June 2002, Abraxas sold its interest in the East White Point field
in Texas for approximately $9.7 million.
In July 2002, Canadian Abraxas and Old Grey Wolf sold their interest
in the Milarville field in Alberta, Canada for approximately $1.1 million.
2003 DRILLING RESULTS
In the Peace River Arch area of western Alberta, New Grey Wolf
successfully completed a well drilled during the first quarter of 2003 which
is currently producing an average of 1.2 MMcfe per day. Two additional wells
were drilled in the area during the second quarter. One well has casing set
and is awaiting completion. The other well is currently drilling. In the Lady
Fern area of northeastern British Columbia, current combined production is
approximately an average of 7.5 MMcfe per day from three wells with a 16.7%
working interest. New Grey Wolf is currently adding compression to reduce the
line pressure, currently 1200 psi, to approximately 450 psi to increase
production from these wells. In the Caroline area of southwestern Alberta, a
well has been drilled and logged pursuant to a farmout agreement with
PrimeWest and is awaiting completion. In west Texas, under a joint
participation agreement with EOG Resources, the sixth horizontal well in the
Montoya formation was completed with an initial rate of 16 MMcfe per day. The
well is currently producing an average of 8 MMcfe per day. We hold a 20%
working interest in the well. Also in west Texas, we are currently drilling a
17,000 foot vertical well in the ROC field to evaluate the Devonian and
Ellenburger formations. We own a 37.5% working interest in the well, which is
currently drilling below 14,100 feet.
MARKETS AND CUSTOMERS
The revenue generated by our operations is highly dependent upon the
prices of, and demand for, crude oil and natural gas. Historically, the markets
for crude oil and natural gas have been volatile and are likely to continue to
be volatile in the future. The prices we receive for our crude oil and natural
gas production and the level of such production are subject to wide fluctuations
and depend on numerous factors beyond our control including seasonality, the
condition of the United States economy (particularly the manufacturing sector),
foreign imports, political conditions in other crude oil-producing and natural
gas-producing countries, the actions of the Organization of Petroleum Exporting
Countries and domestic regulation, legislation and policies. Decreases in the
prices of crude oil and natural gas have had, and could have in the future, an
adverse effect on the carrying value of our proved reserves and our revenue,
profitability and cash flow from operations. You should read the discussion
under "Risk Factors--Risks Relating to Our Business--Crude oil and natural gas
prices and their volatility could adversely affect our revenues, cash flows and
profitability" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Critical Accounting Policies" for more information
relating to the effects on us of decreases in crude oil and natural gas prices.
In order to manage our exposure to price risks in the marketing of our
crude oil and natural gas, from time to time we have entered into fixed price
delivery contracts, financial swaps and crude oil and natural gas futures
contracts as hedging devices. To ensure a fixed price for future production, we
may sell a futures contract and thereafter either (i) make physical delivery of
crude oil or natural gas to comply with such contract or (ii) buy a matching
futures contract to unwind our futures position and sell our production to a
customer. These contracts may expose us to the risk of financial loss in certain
circumstances, including instances where production is less than expected, our
customers fail to purchase or deliver the contracted quantities of crude oil or
natural gas, or a sudden, unexpected event materially impacts crude oil or
natural gas prices. These contracts may also restrict our ability to benefit
from unexpected increases in crude oil and natural gas prices. You should read
the discussion under "Management's Discussion and Analysis of Financial
Condition And Results of Operations -- Liquidity and Capital Resources," and
"Quantitative and Qualitative Disclosures about Market Risk--Commodity Price
Risk" for more information regarding our historical hedging activities.
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"Quantitative and Qualitative Disclosures about Market Risk--Commodity Price
Risk" for more information regarding our historical hedging activities.
Substantially all of our crude oil and natural gas is sold at current
market prices under short-term arrangements, as is customary in the industry.
During the year ended December 31, 2002, three purchasers accounted for
approximately 77% of our United States crude oil and natural gas sales and one
customer accounted for approximately 80% of our crude oil and natural gas sales
in Canada. We believe that there are numerous other companies available to
purchase our crude oil and natural gas and that the loss of one or more of these
purchasers would not materially affect our ability to sell crude oil and natural
gas. The prices we realize for the sale of our crude oil and natural gas are
subject to our hedging activities. You should read the discussion under
"Management's Discussion and Analysis of Financial Condition And Results of
Operations -- Liquidity and Capital Resources" and "Quantitative and Qualitative
Disclosures about Market Risk--Commodity Price Risk" for more historical
information regarding our hedging activities.
PRIMARY OPERATING AREAS
TEXAS
Our U.S. operations are concentrated in South and West Texas with over
99% of the PV-10 of our U.S. crude oil and natural gas properties at December
31, 2002 located in those two regions. We operate 94% of our wells in Texas.
Operations in South Texas are concentrated along the Edwards trend in Live Oak
and Dewitt Counties, the Frio/Vicksburg trend in San Patricio County and the
Wilcox trend in Goliad County. In total in South Texas we own an average 88%
working interest in 44 wells with average daily production of 291 net Bbls of
crude oil and NGLs and 8,177 net Mcf of natural gas per day for the year ended
December 31, 2002. As of December 31, 2002 we had estimated net proved reserves
in South Texas of 31,103 Mmcfe (83% natural gas) with a PV-10 of $47.2 million,
70% of which was attributable to proved developed reserves. Our West Texas
operations are concentrated along the deep Devonian/Ellenberger formations and
shallow Cherry Canyon sandstones in Ward County, the Spraberry trend in Midland
County and in the Sharon Ridge Clearfork Field in Scurry County. Abraxas entered
into a farmout agreement with EOG Resources Inc. whereby EOG earned a 75%
working interest in Abraxas' then existing Montoya acreage by paying Abraxas
$2.5 million and paying 100% of the cost of the first five wells, the last of
which came on line in December 2002. EOG remains under an obligation to continue
developing the acreage; however, Abraxas will be responsible for its pro-rata
share of the drilling and development costs going forward. Two wells were
planned for 2003. One well was completed and is producing and the second well is
currently drilling. In total in West Texas we own an average 75% working
interest in 157 wells with average daily production of 389 net Bbls of crude oil
and NGLs and 6,814 net Mcf of natural gas per day for the year ended December
31, 2002. As of December 31, 2002, we had estimated net proved reserves in West
Texas of 65,957 Mmcfe (80% natural gas) with a PV 10 of $62.7 million, 39% of
which was attributable to proved developed reserves. During 2002, we drilled a
total of 3 new wells (1.06 net) in Texas with a 67% success rate.
WYOMING
We currently hold over 60,000 contiguous acres in the Powder River
Basin in east central Wyoming. We have drilled and operate five wells in
Converse and Niobrara counties that were completed in the Turner and Niobrara
formations. We own a 100% working interest in these wells that produced an
average of 43 net barrels of crude oil per day in 2002. As of December 31, 2002,
we had estimated net proved producing reserves in Wyoming of 91,791 barrels of
crude oil with a PV-10 of $427,000.
WESTERN CANADA
We own properties in western Canada, consisting primarily of natural
gas reserves and undeveloped acreage in the provinces of Alberta and British
Columbia. Our Alberta properties are in two concentrated areas: the Caroline
field, 60 miles northwest of Calgary, and the Peace River Arch area in
northwestern Alberta. We have entered into a farmout agreement with PrimeWest in
connection with the sale of Canadian Abraxas and Old Grey Wolf to jointly
develop these areas in the future - (see Recent Events). Our other Canadian
operations are located in the Ladyfern area of northeast British Columbia. In
this area we participated in six wells being drilled during 2002 with a 50%
success rate. As of December
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31, 2002, Canadian Abraxas and Old Grey Wolf had estimated net proved
reserves of 68.8 Bcfe (88% natural gas) with a PV-10 of $144.5 million of
which 93% was attributable to proved developed reserves. As of December 31,
2002, giving effect to the transactions which occurred in January 2003, New
Grey Wolf had estimated net proved reserves of 14.9 Bcfe (91% natural gas)
with a PV-10 of $26.3 million, 61% of which was attributable to proved
developed reserves. For the year ended December 31, 2002, the Canadian
properties produced an average of approximately 740.5 net Bbls of crude oil
and NGLs per day and 27,345.6 net Mcf of natural gas per day. During 2002, we
drilled a total of 20 new wells (15.7 net) in Canada with a 90% success rate.
EXPLORATORY AND DEVELOPMENTAL ACREAGE
Our principal crude oil and natural gas properties consist of
non-producing and producing crude oil and natural gas leases, including reserves
of crude oil and natural gas in place. The following table indicates our
interest in developed and undeveloped acreage as of December 31, 2002:
<Table>
<Caption>
Developed and Undeveloped Acreage
-----------------------------------------------------------------------
As of December 31, 2002
-----------------------------------------------------------------------
Developed Acreage Undeveloped Acreage
--------------------------------- ------------------------------------
Gross Acres Net Acres Gross Acres Net Acres
--------------- --------------- --------------- ------------------
Canada (1) 84,335 49,429 367,315 285,827
Texas 24,775 19,911 10,881 10,029
Wyoming 3,200 3,200 58,311 54,478
--------------- --------------- --------------- ------------------
Total 112,310 72,540 436,507 350,334
=============== =============== =============== ==================
</Table>
- ----------
(1) Includes 73,840 gross (43,997 net) developed acres and 15,097 gross (8,288
net) undeveloped acres that were sold in connection with the sale of
Canadian Abraxas and Old Grey Wolf in January 2003, "Business - Recent
Events".
PRODUCTIVE WELLS
The following table sets forth our total gross and net productive
wells expressed separately for crude oil and natural gas, as of December 31,
2002:
<Table>
<Caption>
Productive Wells
---------------------------------------------------------------------
As of December 31, 2002
---------------------------------------------------------------------
State/Country Crude Oil Natural Gas
--------------------- -------------------------------- ----------------------------------
Gross Net Gross Net
--------------- -------------- --------------- ----------------
Canada (1) 243.0 5.6 121.0 66.4
Texas 139.0 111.3 62.0 45.2
Wyoming 5.0 5.0 - -
--------------- -------------- --------------- ----------------
Total 387.0 121.9 183.0 111.6
=============== ============== =============== ================
</Table>
- ----------
(1) Includes 228.0 gross (4.3 net) crude oil wells and 114.0 gross (65.0 net)
natural gas wells that were sold in connection with the sale of Canadian
Abraxas and Old Grey Wolf in January 2003, see "Business - Recent Events".
RESERVES INFORMATION
The crude oil and natural gas reserves of the U.S. operations only
have been estimated as of January 1, 2003, January 1, 2002, and January 1, 2001,
by DeGolyer and MacNaughton, of Dallas, Texas. The reserves of the Canadian
operations as of January 1, 2002 and January 1, 2001 have been estimated by
McDaniel and Associates Consultants Ltd. of Calgary, Alberta. The January 1,
2003 reserves attributable to the Canadian operations were estimated internally.
Crude oil and natural gas reserves, and the estimates of the present value of
future net revenues therefrom, were determined based on then current prices and
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<Page>
costs. Reserve calculations involve the estimate of future net recoverable
reserves of crude oil and natural gas and the timing and amount of future net
revenues to be received there from. Such estimates are not precise and are based
on assumptions regarding a variety of factors, many of which are variable and
uncertain.
The following table sets forth certain information regarding estimates
of our crude oil, natural gas liquids and natural gas reserves as of January 1,
2001, January 1, 2002 and January 1, 2003:
<Table>
<Caption>
ESTIMATED PROVED RESERVES
----------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
As of January 1, 2001
Crude oil (MBbls) 3,866 1,407 5,273
NGLs (MBbls) 3,135 436 3,571
Natural gas (MMcf) 119,737 71,590 191,327
As of January 1, 2002
Crude oil (MBbls) 1,980 1,170 3,150
NGLs (MBbls) 3,067 585 3,652
Natural gas (MMcf) 111,243 77,514 188,757
As of January 1, 2003 (1)
Crude oil (MBbls) 1,782 1,317 3,099
NGLs (MBbls) 1,222 284 1,506
Natural gas (MMcf) 90,374 48,458 138,832
</Table>
- ----------
Reserves on a Mcf equivalent at December 31, 2002 were 146.5 Bcfe. Crude
oil and natural gas liquids are converted to a Mcf equivalent (Mcfe) on the
basis of 1 Bbl of crude oil and natural gas liquid equals 6 Mcf of natural
gas.
(1) Reserves as of January 1, 2003 include 67 MBbls of crude oil,
1,079 MBbls of NGLs, and 47,066 MMcf of natural gas that were sold in connection
with the sale of Canadian Abraxas and Old Grey Wolf in January 2003, see
"Business - Recent Events".
The process of estimating crude oil and natural gas reserves is
complex and involves decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data. Therefore, these
estimates are imprecise.
Actual future production, crude oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable crude oil and natural gas reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this prospectus. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing crude oil and
natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues
referred to in this prospectus is the current market value of our estimated
crude oil and natural gas reserves. In accordance with SEC requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of the year of the estimate, or
alternatively, if prices subsequent to that date have increased, a price near
the periodic filing date of our financial statements. As of December 31, 2001,
our net capitalized costs of crude oil and natural gas properties exceeded the
present value of our estimated proved reserves by $38.9 million on U.S.
properties. This amount was calculated considering 2001 year-end prices of
$19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to
reflect the expected realized prices for each of the full cost pools. We did not
adjust our capitalized costs for U.S. properties because subsequent to
December 31, 2001, crude oil and natural gas prices increased such that
capitalized costs for U.S.
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properties did not exceed the present value of the estimated proved crude oil
and natural gas reserves for U.S. properties as determined using increased
realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per
Mcf for natural gas.
At 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). These amounts were calculated considering June 30, 2002
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. Subsequent to June 30, 2002, commodity prices increased in Canada and we
utilized these increased prices in calculating the ceiling limitation
write-down. The total write-down was approximately $116.0 million. At December
31, 2002, our net capitalized cost of crude oil and natural gas properties did
not exceed the present value of our estimated reserves, due to increased
commodity prices during the fourth quarter and, as such, no further write-down
was recorded. We cannot assure you that we will not experience additional
ceiling limitation write-downs in the future.
Actual future prices and costs may be materially higher or lower than
the prices and costs as of the end of the year of the estimate. Any changes in
consumption by natural gas purchasers or in governmental regulations or taxation
will also affect actual future net cash flows. The timing of both the production
and the expenses from the development and production of crude oil and natural
gas properties will affect the timing of actual future net cash flows from
proved reserves and their present value In addition, the 10% discount factor,
which is required by the SEC to be used in calculating discounted future net
cash flows for reporting purposes, is not necessarily the most accurate discount
factor. The effective interest rate at various times and the risks associated
with us or the crude oil and natural gas industry in general will affect the
accuracy of the 10% discount factor.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of crude oil and natural gas reserves, future net
revenue from proved reserves and the PV-10 thereof for the crude oil and natural
gas properties described in this prospectus are based on the assumption that
future crude oil and natural gas prices remain the same as crude oil and natural
gas prices at December 31, 2002. The average sales prices as of such date used
for purposes of such estimates were $29.69 per Bbl of crude oil, $18.89 per Bbl
of NGLs and $3.79 per Mcf of natural gas. It is also assumed that we will make
future capital expenditures of approximately $59.5million in the aggregate,
which are necessary to develop and realize the value of proved undeveloped
reserves on our properties. Any significant variance in actual results from
these assumptions could also materially affect the estimated quantity and value
of reserves set forth herein.
We file reports of our estimated crude oil and natural gas reserves
with the Department of Energy and the Bureau of the Census. The reserves
reported to these agencies are required to be reported on a gross operated basis
and therefore are not comparable to the reserve data reported herein.
CRUDE OIL, NATURAL GAS LIQUIDS, AND NATURAL GAS PRODUCTION AND SALES PRICES
The following table presents our net crude oil, net natural gas
liquids and net natural gas production, the average sales price per Bbl of crude
oil and natural gas liquids and per Mcf of natural gas produced and the average
cost of production per BOE of production sold, for the three years ended
December 31, 2002.
<Table>
<Caption>
2000 2001 2002
---------------- --------------- ----------------
Crude oil production (Bbls) 636,734 454,063 292,264
Natural gas production (Mcf) 19,962,470 17,495,598 15,452,721
Natural gas liquids production
(Bbls) 314,897 277,969 242,032
</Table>
57
<Page>
<Table>
MMcfe 25,672 21,888 18,658
Average sales price per Bbl of
crude oil $ 18.69 $ 24.63 $ 24.34
Average sales price per MCF of
natural gas (1) $ 2.71 $ 3.20 $ 2.55
Average sales price per Bbl of
natural gas liquids $ 22.42 $ 21.51 $ 17.94
Average sales price per Mcfe $ 2.82 $ 3.35 $ 2.72
Average cost of production per
Mcfe produced (2) $ 0.74 $ 0.85 $ 0.82
</Table>
(1) Average sales prices are net of hedging activity.
(2) Crude oil and natural gas were combined by converting crude oil and natural
gas liquids to a Mcf equivalent ("Mcfe") on the basis of 1 Bbl of crude oil
and natural gas liquid equals 6 Mcf of natural gas. Production costs
include direct operating costs, ad valorem taxes and gross production
taxes.
DRILLING ACTIVITIES
The following table sets forth our gross and net working interests in
exploratory and development wells drilled during the three years ended December
31, 2002.
<Table>
<Caption>
2000 2001 2002
----------------------------- ----------------------------- -------------------------
Gross Net Gross Net Gross Net
------------ ---------- ------------ ---------- ---------- --------
Exploratory
Productive
Crude oil - - - - 1.0 1.0
Natural gas 3.0 2.5 2.0 1.0 3.0 0.5
Dry holes 9.0 5.6 1.0 .5 3.0 1.5
------------ ---------- ------------ ---------- ---------- --------
Total 12.0 8.1 3.0 1.5 7.0 3.0
============ ========== ============ ========== ========== ========
Development
Productive
Crude oil 9.0 9.0 2.0 2.0 - -
Natural gas 16.0 12.2 13.0 11.0 14.0 11.8
Dry holes 3.0 3.0 - - 1.0 1.0
------------ ---------- ------------ ---------- ---------- --------
Total 28.0 24.2 15.0 13.0 15.0 12.8
============ ========== ============ ========== ========== ========
</Table>
- ----------
COMPETITION
We operate in a highly competitive environment. Competition is
particularly intense with respect to the acquisition of desirable undeveloped
crude oil and natural gas properties. The principal competitive factors in the
acquisition of such undeveloped crude oil and natural gas properties include the
staff and data
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<Page>
necessary to identify, investigate and purchase such properties, and the
financial resources necessary to acquire and develop such properties. We compete
with major and independent crude oil and natural gas companies for properties
and the equipment and labor required to develop and operate such properties.
Many of these competitors have financial and other resources substantially
greater than ours.
The principal resources necessary for the exploration and production
of crude oil and natural gas are leasehold prospects under which crude oil and
natural gas reserves may be discovered, drilling rigs and related equipment to
explore for such reserves and knowledgeable personnel to conduct all phases of
crude oil and natural gas operations. We must compete for such resources with
both major crude oil and natural gas companies and independent operators.
Although we believe our current operating and financial resources are adequate
to preclude any significant disruption of our operations in the immediate future
we cannot assure you that such materials and resources will be available to us.
We face significant competition for obtaining additional natural gas
supplies for gathering and processing operations, for marketing NGLs, residue
gas, helium, condensate and sulfur, and for transporting natural gas and
liquids. Our principal competitors include major integrated oil companies and
their marketing affiliates and national and local gas gatherers, brokers,
marketers and distributors of varying sizes, financial resources and experience.
Certain competitors, such as major crude oil and natural gas companies, have
capital resources and control supplies of natural gas substantially greater than
ours. Smaller local distributors may enjoy a marketing advantage in their
immediate service areas.
We compete against other companies in our natural gas processing
business both for supplies of natural gas and for customers to which we sell our
products. Competition for natural gas supplies is based primarily on location of
natural gas gathering facilities and natural gas gathering plants, operating
efficiency and reliability and ability to obtain a satisfactory price for
products recovered. Competition for customers is based primarily on price and
delivery capabilities.
REGULATION OF CRUDE OIL AND NATURAL GAS ACTIVITIES
The exploration, production and transportation of all types of
hydrocarbons are subject to significant governmental regulations. Our operations
are affected from time to time in varying degrees by political developments and
federal, state, provincial and local laws and regulations. In particular, crude
oil and natural gas production operations and economics are, or in the past have
been, affected by industry specific price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, by changes in
such laws and by constantly changing administrative regulations.
PRICE REGULATIONS
In the past, maximum selling prices for certain categories of crude
oil, natural gas, condensate and NGLs in the United States were subject to
significant federal regulation. At the present time, however, all sales of our
crude oil, natural gas, condensate and NGLs produced in the United States under
private contracts may be sold at market prices. Congress could, however, reenact
price controls in the future. If controls that limit prices to below market
rates are instituted, our revenue would be adversely affected.
Crude oil and natural gas exported from Canada is subject to
regulation by the National Energy Board ("NEB") and the government of Canada.
Exporters are free to negotiate prices and other terms with purchasers, provided
that export contracts in excess of two years must continue to meet certain
criteria prescribed by the NEB and the government of Canada. Crude oil and
natural gas exports for a term of less than two years must be made pursuant to
an NEB order, or, in the case of exports for a longer duration, pursuant to an
NEB license and Governor in Council approval.
The provincial governments of Alberta, British Columbia and
Saskatchewan also regulate the volume of natural gas that may be removed from
these provinces for consumption elsewhere based on such factors as reserve
availability, transportation arrangements and marketing considerations.
THE NORTH AMERICAN FREE TRADE AGREEMENT
On January 1, 1994, the North American Free Trade Agreement ("NAFTA")
among the governments of the United States, Canada and Mexico became effective.
In the context of energy
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resources, Canada remains free to determine whether exports to the U.S. or
Mexico will be allowed provided that any export restrictions do not: (i) reduce
the proportion of energy resources exported relative to the total supply of the
energy resource (based upon the proportion prevailing in the most recent 36
month period); (ii) impose an export price higher than the domestic price; or
(iii) disrupt normal channels of supply. All three countries are prohibited from
imposing minimum export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade
practices in the energy sector and prohibits discriminatory border restrictions
and export taxes. The agreement also contemplates clearer disciplines on
regulators to ensure fair implementation of any regulatory changes and to
minimize disruption of contractual arrangements, which is important for Canadian
natural gas exports. The Texas Railroad Commission has recently become the lead
agency for Texas for coordinating permits governing Texas to Mexico cross border
pipeline projects. The availability of selling natural gas into Mexico may
substantially impact the interstate natural gas market on all producers in the
coming years.
UNITED STATES NATURAL GAS REGULATION
Historically, the natural gas industry as a whole has been more
heavily regulated than the crude oil or other liquid hydrocarbons market. Most
regulations focused on transportation practices. In the recent past interstate
pipeline companies in the United States generally acted as wholesale merchants
by purchasing natural gas from producers and reselling the natural gas to local
distribution companies and large end users. Commencing in late 1985, the Federal
Energy Regulatory Commission (the "FERC") issued a series of orders that have
had a major impact on interstate natural gas pipeline operations, services, and
rates, and thus have significantly altered the marketing and price of natural
gas. The FERC's key rule making action, Order No. 636 ("Order 636"), issued in
April 1992, required each interstate pipeline to, among other things, "unbundle"
its traditional bundled sales services and create and make available on an open
and nondiscriminatory basis numerous constituent services (such as gathering
services, storage services, firm and interruptible transportation services, and
standby sales and natural gas balancing services), and to adopt a new ratemaking
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate markets natural gas as a merchant, it
does so pursuant to private contracts in direct competition with all of the
sellers, such as us; however, pipeline companies and their affiliates were not
required to remain "merchants" of natural gas, and most of the interstate
pipeline companies have become "transporters only," although many have
affiliated marketers. Order 636 and related FERC orders have resulted in
increased competition within all phases of the natural gas industry. We do not
believe that Order 636 and the related restructuring proceedings affect us any
differently than other natural gas producers and marketers with which we
compete.
Transportation pipeline availability and cost are major factors
affecting the production and sale of natural gas. Our physical sales of natural
gas are affected by the actual availability, terms and cost of pipeline
transportation. The price and terms for access onto the pipeline transportation
systems remain subject to extensive Federal regulation. Although Order 636 does
not directly regulate our production and marketing activities, it does affect
how buyers and sellers gain access to and use of the necessary transportation
facilities and how we and our competitors sell natural gas in the marketplace.
The courts have largely affirmed the significant features of Order No. 636 and
the numerous related orders pertaining to individual pipelines, although some
appeals remain pending and the FERC continues to review and modify its
regulations regarding the transportation of natural gas. For example, the FERC
has recently begun a broad review of its natural gas transportation regulations,
including how its regulations operate in conjunction with state proposals for
natural gas marketing restructuring and in the increasingly competitive
marketplace for all post-wellhead services related to natural gas.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural gas
in the United States. Some of the more notable of these regulatory initiatives
include:
(1) a series of orders in individual pipeline proceedings articulating a
policy of generally approving the voluntary divestiture of interstate
pipeline owned gathering facilities by interstate pipelines to their
affiliates (the so-called "spin down" of previously regulated
gathering facilities to the pipeline's nonregulated affiliates).
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(2) Order No. 497 involving the regulation of pipelines with marketing
affiliates.
(3) various FERC orders adopting rules proposed by the Gas Industry
Standards Board which are designed to further standardize pipeline
transportation tariffs and business practices.
(4) a notice of proposed rulemaking that, among other things, proposes (a)
to eliminate the cost-based price cap currently imposed on natural gas
transactions of less than one year in duration, (b) to establish
mandatory "transparent" capacity auctions of short-term capacity on a
daily basis, and (c) to permit interstate pipelines to negotiate terms
and conditions of service with individual customers.
(5) issuance of Policy Statements regarding Alternate Rates and Negotiated
Terms and Conditions of Service covering (a)the pricing of long-term
pipeline transportation services by alternative rate mechanism
options, including the pricing of interstate pipeline capacity
utilizing market-based rates, incentive rates, or indexed rates, and
(b) investigating of whether FERC should permit pipelines to negotiate
the terms and conditions of service, in addition to rates of service.
(6) a notice of proposed rulemaking that proposes generic procedures to
expedite the FERC's handling of complaints against interstate
pipelines with the goals of encouraging and supporting consensual
resolutions of complaints and organizing the complaint procedures so
that all complaints are handled in a timely and fair manner.
Several of these initiatives are intended to enhance competition in
natural gas markets, although some, such as "spin downs," may have the adverse
effect of increasing the cost of doing business on some in the industry,
including us, as a result of the geographic monopolization of those facilities
by their new, unregulated owners. As to all of these FERC initiatives, the
ongoing, or, in some instances, preliminary and evolving nature of these
regulatory initiatives makes it impossible at this time to predict their
ultimate impact on our business. However, we do not believe that these FERC
initiatives will affect us any differently than other natural gas producers and
marketers with which we compete.
Since Order 636, FERC decisions involving onshore facilities have been
more liberal in their reliance upon traditional tests for determining what
facilities are "gathering" and therefore exempt from federal regulatory control.
In many instances, what was once classified as "transmission" may now be
classified as "gathering." We ship certain of our natural gas through gathering
facilities owned by others, including interstate pipelines, under existing long
term contractual arrangements. Although these FERC decisions have created the
potential for increasing the cost of shipping our natural gas on third party
gathering facilities, our shipping activities have not been materially affected
by these decisions.
In summary, all of the FERC activities related to the transportation
of natural gas have resulted in improved opportunities to market our physical
production to a variety of buyers and market places, while at the same time
increasing access to pipeline transportation and delivery services. Additional
proposals and proceedings that might affect the natural gas industry in the
United States are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. We cannot predict when or if any such
proposals might become effective or their effect, if any, on our operations. The
crude oil and natural gas industry historically has been very heavily regulated;
thus there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue indefinitely into the future.
STATE AND OTHER REGULATION
All of the jurisdictions in which we own producing crude oil and
natural gas properties have statutory provisions regulating the exploration for
and production of crude oil and natural gas, including provisions requiring
permits for the drilling of wells and maintaining bonding requirements in order
to drill or operate wells and provisions relating to the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and abandoning of
wells. Our operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and spacing
units or proration units on an acreage basis and the density of wells which may
be drilled and the unitization or pooling of crude oil and natural gas
properties. In this regard, some states and provinces allow the forced pooling
or integration of tracts to facilitate exploration while other states and
provinces rely on voluntary pooling of lands and leases. In addition, state and
provincial conservation laws establish maximum rates of production from crude
oil and natural gas wells,
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<Page>
generally prohibit the venting or flaring of natural gas and impose certain
requirements regarding the ratability of production. Some states, such as Texas
and Oklahoma, have, in recent years, reviewed and substantially revised methods
previously used to make monthly determinations of allowable rates of production
from fields and individual wells. The effect of all of these conservation
regulations is to limit the speed, timing and amounts of crude oil and natural
gas we can produce from our wells, and to limit the number of wells or the
location at which we can drill.
State and provincial regulation of gathering facilities generally
includes various safety, environmental, and in some circumstances,
non-discriminatory take requirements, but does not generally entail rate
regulation. In the United States, natural gas gathering has received greater
regulatory scrutiny at both the state and federal levels in the wake of the
interstate pipeline restructuring under Order 636. For example, the Texas
Railroad Commission enacted a Natural Gas Transportation Standards and Code of
Conduct to provide regulatory support for the State's more active review of
rates, services and practices associated with the gathering and transportation
of natural gas by an entity that provides such services to others for a fee, in
order to prohibit such entities from unduly discriminating in favor of their
affiliates.
For those operations on U.S. Federal or Indian oil and gas leases,
such operations must comply with numerous regulatory restrictions, including
various non-discrimination statutes, and certain of such operations must be
conducted pursuant to certain on-site security regulations and other permits
issued by various federal agencies. In addition, in the United States, the
Minerals Management Service ("MMS") has recently issued a final rule to clarify
or severely limit the types of costs that are deductible transportation costs
for purposes of royalty valuation of production sold off the lease. In
particular, MMS will not allow deduction of costs associated with marketer fees,
cash out and other pipeline imbalance penalties, or long-term storage fees.
Further, the MMS has been engaged in a process of promulgating new rules and
procedures for determining the value of crude oil produced from federal lands
for purposes of calculating royalties owed to the government. The crude oil and
natural gas industry as a whole has resisted the proposed rules under an
assumption that royalty burdens will substantially increase. We cannot predict
what, if any, effect any new rule will have on our operations.
CANADIAN ROYALTY MATTERS
In addition to Canadian federal regulation, each province has
legislation and regulations that govern land tenure, royalties, production
rates, environmental protection and other matters. The royalty regime is a
significant factor in the profitability of crude oil and natural gas production.
Royalties payable on production from lands other than Crown lands are determined
by negotiations between the mineral owner and the lessee. Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of royalties
payable generally depends in part on prescribed preference prices, well
productivity, geographical location, field discovery date and the type and
quality of the petroleum product produced.
From time to time the governments of Alberta and British Columbia, the
provinces where almost all of New Grey Wolf's production is located, have
established incentive programs which have included royalty rate reductions,
royalty holidays and tax credits for the purpose of encouraging crude oil and
natural gas exploration or enhanced planning projects. All of New Grey Wolf's
production is from oil and gas rights which have been granted by the Provinces.
The Province of Alberta requires the payment from lessees of oil and
gas rights of annual rental payments as well as royalty payments. Regulations
made pursuant to the Mines and Minerals Act (Alberta) provide various incentives
for exploring and developing crude oil reserves in Alberta. Crude oil produced
from horizontal extensions commenced at least five years after the well was
originally spudded may qualify for a royalty reduction. An 8,000 cubic meters
exemption is available to production from a well that has not produced for a
12-month period prior to January 31, 1993 or 24 months following such date. In
addition, crude oil production from eligible new field and new pool wildcat
wells and deeper pool test wells spudded or deepened after September 30, 1992,
is entitled to a 12-month royalty exemption (to a maximum of CDN $1 million).
Crude oil produced from low productivity wells, enhanced recovery schemes (such
as injection wells) and experimental projects is also subject to royalty
reductions.
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The Alberta government classifies conventional crude oil into three
categories, being Old Oil, New Oil and Third Tier Oil. Each have a base royalty
rate of 10%. The rate caps on the categories are 25% for oil from crude oil
pools discovered after September 30, 1992, being the Third Tier Oil, 30% for oil
from pools or pool extensions discovered after April 1, 1974, from wells drilled
or deepened after October 31, 1991 or from reactivated wells and which are not
Third Tier Oil, and 35% for Old Oil.
Effective January 1, 1994, the calculation and payment of natural gas
royalties became subject to a simplified process. The royalty reserved to the
Crown, subject to various incentives, is between 15% or 30%, in the case of new
natural gas, and between 15% and 35%, in the case of old natural gas, depending
upon a prescribed or corporate average reference price. Natural gas produced
from qualifying exploratory gas wells spudded or deepened after July 1, 1985 and
before June 1, 1988 are eligible for a royalty exemption for a period of 12
months, or such later time that the value of the exempted royalty quantity
equals a prescribed maximum amount. Natural gas produced from qualifying
intervals in eligible natural gas wells spudded or deepened to a depth below
2,500 meters is also subject to a royalty exemption, the amount of which depends
on the depth of the well.
In Alberta, a producer of crude oil or natural gas is entitled to
credit against the royalties payable to the Crown by virtue of the Alberta
Royalty Tax Credit ("ARTC") program. The ARTC program is based on a
price-sensitive formula, and the ARTC rate currently varies between 75% for
prices for crude oil at or below CDN $100 per cubic meter and 35% for prices
above CDN $210 per cubic meter. The ARTC rate is currently applied to a maximum
of CDN $2.0 million of Alberta Crown royalties payable for each producer or
associated group of producers. Crown royalties on production from producing
properties acquired from corporations claiming maximum entitlement to ARTC will
generally not be eligible for ARTC. The rate is established quarterly based on
average "par price", as determined by the Alberta Department of Energy for the
previous quarterly period.
Producers of crude oil and natural gas in British Columbia are also
required to pay annual rental payments in respect of Crown leases and royalties
and freehold production taxes in respect of crude oil and natural gas produced
from Crown and freehold lands respectively. British Columbia also classifies
conventional crude oil into the three categories of Old Oil, New Oil and Third
Tier Oil. The amount payable as a royalty in respect of crude oil depends on the
vintage of the crude oil (whether it was produced from a pool discovered before
or after October 31, 1975) or a pool in which no well was completed on June 1,
1998), the quantity of crude oil produced in a month and the value of the crude
oil. Crude oil produced from a discovery well may be exempt from the payment of
a royalty for the first 36 months of production to a maximum production of
11,450 m3. The royalty payable on natural gas is determined by a sliding scale
based on a classification of the gas based on whether it is conservation gas
(gas associated with marketed oil production) and by drilling and land lease
date and on a reference price which is the greater of the amount obtained by the
producer and at prescribed minimum price. Conservation gas has a minimum royalty
of 8%. The royalty rate ranges from between 9% and 27% for wells drilled on
lands issued after May 31, 1998 and before January 1, 2003 and completed within
5 years of the date the lands were issued and between 12% and 27% for wells
spudded after May 31, 1998 on lands where rights had been issued as of May 31,
1998.
ENVIRONMENTAL MATTERS
Our operations are subject to numerous federal, state, provincial and
local laws and regulations controlling the generation, use, storage, and
discharge of materials into the environment or otherwise relating to the
protection of the environment. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences; restrict the types, quantities, and concentrations of various
substances that can be released into the environment in connection with
drilling, production, and natural gas processing activities; suspend, limit or
prohibit construction, drilling and other activities in certain lands lying
within wilderness, wetlands, and other protected areas; require remedial
measures to mitigate pollution from historical and on-going operations such as
use of pits and plugging of abandoned wells; restrict injection of liquids into
subsurface strata that may contaminate groundwater; and impose substantial
liabilities for pollution resulting from our operations. Environmental permits
required for our operations may be subject to revocation, modification, and
renewal by issuing authorities. Governmental authorities have the power to
enforce compliance with their regulations and permits, and violations are
subject to injunction, civil fines, and even criminal penalties. Our management
believes that
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we are in substantial compliance with current environmental laws and
regulations, and that we will not be required to make material capital
expenditures to comply with existing laws. Nevertheless, changes in existing
environmental laws and regulations or interpretations thereof could have a
significant impact on us as well as the crude oil and natural gas industry in
general, and thus we are unable to predict the ultimate cost and effects of
future changes in environmental laws and regulations.
In the United States, the Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), also known as "Superfund," and
comparable state statutes impose strict, joint, and several liability on certain
classes of persons who are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of a disposal site or sites where a release occurred and companies that
generated, disposed or arranged for the disposal of the hazardous substances
released at the site. Under CERCLA such persons or companies may be
retroactively liable for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is common for neighboring land owners and other third parties to file
claims for personal injury, property damage, and recovery of response costs
allegedly caused by the hazardous substances released into the environment. The
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes
govern the disposal of "solid waste" and "hazardous waste" and authorize
imposition of substantial civil and criminal penalties for failing to prevent
surface and subsurface pollution, as well as to control the generation,
transportation, treatment, storage and disposal of hazardous waste generated by
crude oil and natural gas operations. Although CERCLA currently contains a
"petroleum exclusion" from the definition of "hazardous substance," state laws
affecting our operations impose cleanup liability relating to petroleum and
petroleum related products, including crude oil cleanups. In addition, although
RCRA regulations currently classify certain oilfield wastes which are uniquely
associated with field operations as "non-hazardous," such exploration,
development and production wastes could be reclassified by regulation as
hazardous wastes thereby administratively making such wastes subject to more
stringent handling and disposal requirements.
We currently own or lease, and have in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of crude oil and natural gas. Although we utilized standard industry
operating and disposal practices at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties we owned or leased
or on or under other locations where such wastes have been taken for disposal.
In addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon may be subject to
CERCLA, RCRA, and analogous state laws. Our operations are also impacted by
regulations governing the disposal of naturally occurring radioactive materials
("NORM"). We must comply with the Clean Air Act and comparable state statutes
which prohibit the emissions of air contaminants, although a majority of our
activities are exempted under a standard exemption. Moreover, owners, lessees
and operators of crude oil and natural gas properties are also subject to
increasing civil liability brought by surface owners and adjoining property
owners. Such claims are predicated on the damage to or contamination of land
resources occasioned by drilling and production operations and the products
derived therefrom, and are usually causes of action based on negligence,
trespass, nuisance, strict liability and fraud.
United States federal regulations also require certain owners and
operators of facilities that store or otherwise handle crude oil, such as us, to
prepare and implement spill prevention, control and countermeasure plans and
spill response plans relating to possible discharge of crude oil into surface
waters. The federal Oil Pollution Act ("OPA") contains numerous requirements
relating to prevention of, reporting of, and response to crude oil spills into
waters of the United States. For facilities that may affect state waters, OPA
requires an operator to demonstrate $10 million in financial responsibility.
State laws mandate crude oil cleanup programs with respect to contaminated soil.
Our Canadian operations are also subject to environmental regulation
pursuant to local, provincial and federal legislation which generally require
operations to be conducted in a safe and environmentally responsible manner.
Canadian environmental legislation provides for restrictions and prohibitions
relating to the discharge of air, soil and water pollutants and other substances
produced in association with certain crude oil and natural gas industry
operations, and environmental protection requirements, including certain
conditions of approval and laws relating to storage, handling, transportation
and disposal of materials or substances which may have an adverse effect on the
environment. Environmental legislation can affect the
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location of wells and facilities and the extent to which exploration and
development is permitted. In addition, legislation requires that well and
facilities sites be abandoned and reclaimed to the satisfaction of provincial
authorities. A breach of such legislation may result in the imposition of fines
or issuance of clean-up orders.
Certain federal environmental laws that may affect us include the
Canadian Environmental Assessment Act which ensures that the environmental
effects of projects receive careful consideration prior to licenses or permits
being issued, to ensure that projects that are to be carried out in Canada or on
federal lands do not cause significant adverse environmental effects outside the
jurisdictions in which they are carried out, and to ensure that there is an
opportunity for public participation in the environmental assessment process;
the Canadian Environmental Protection Act ("CEPA") which is the most
comprehensive federal environmental statute in Canada, and which controls toxic
substances (broadly defined), includes standards relating to the discharge of
air, soil and water pollutants, provides for broad enforcement powers and
remedies and imposes significant penalties for violations; the National Energy
Board Act which can impose certain environmental protection conditions on
approvals issued under the Act; the Fisheries Act which prohibits the depositing
of a deleterious substance of any type in water frequented by fish or in any
place under any condition where such deleterious substance may enter any such
water and provides for significant penalties; the Navigable Waters Protection
Act which requires any work which is built in, on, over, under, through or
across any navigable water to be approved by the Minister of Transportation, and
which attracts severe penalties and remedies for non-compliance, including
removal of the work.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993.
In addition to consolidating a variety of environmental statutes, the AEPEA also
imposes certain new environmental responsibilities on crude oil and natural gas
operators in Alberta. The AEPEA sets out environmental standards and compliance
for releases, clean-up and reporting. The Act provides for a broad range of
liabilities, enforcement actions and penalties.
We are not currently involved in any administrative, judicial or legal
proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations, or under federal or state common
law, which would have a material adverse effect on our financial position or
results of operations. Moreover, we maintain insurance against costs of clean-up
operations, but we are not fully insured against all such risks. A serious
incident of pollution may result in the suspension or cessation of operations in
the affected area.
We believe that we have obtained and are in compliance with all
material environmental permits, authorizations and approvals.
TITLE TO PROPERTIES
As is customary in the crude oil and natural gas industry, we make
only a cursory review of title to undeveloped crude oil and natural gas leases
at the time we acquire them. However, before drilling commences, we require a
thorough title search to be conducted, and any material defects in title are
remedied prior to the time actual drilling of a well begins. To the extent title
opinions or other investigations reflect title defects, we, rather than the
seller of the undeveloped property, are typically obligated to cure any title
defect at our expense. If we were unable to remedy or cure any title defect of a
nature such that it would not be prudent to commence drilling operations on the
property, we could suffer a loss of our entire investment in the property. We
believe that we have good title to our crude oil and natural gas properties,
some of which are subject to immaterial encumbrances, easements and
restrictions. The crude oil and natural gas properties we own are also typically
subject to royalty and other similar non-cost bearing interests customary in the
industry. We do not believe that any of these encumbrances or burdens will
materially affect our ownership or use of our properties.
EMPLOYEES
As of March 31, 2003, we had 48 full-time employees in the United
States, including 3 executive officers, 3 non-executive officers, 1 petroleum
engineer, 1 geologist, 6 managers, 1 landman, 12 secretarial
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and clerical personnel and 21 field personnel. Additionally, we retain contract
pumpers on a month-to-month basis. We retain independent geological and
engineering consultants from time to time on a limited basis and expect to
continue to do so in the future.
As of March 31, 2003, New Grey Wolf had 13 full-time employees,
including 3 executive officers, 1 non-executive officers, 2 petroleum
engineers, 2 geologists, 1 geophysicist and, 4 technical and clerical
personnel.
OFFICE FACILITIES
Our executive and administrative offices are located at 500 North Loop
1604 East, Suite 100, San Antonio, Texas 78232. We also have an office in
Midland, Texas. These offices, consisting of approximately 12,650 square feet in
San Antonio and 570 square feet in Midland, are leased until March 2006 at an
aggregate base rate of $19,500 per month.
New Grey Wolf leases 17,522 square feet of office space in Calgary,
Alberta pursuant to a lease, which expires in April 2003.
OTHER PROPERTIES
We own 10 acres of land, an office building, workshop, warehouse and
house in Sinton, Texas, 2.8 acres of land, an office building and 600 acres of
fee land in Scurry County, Texas and 160 acres of land in Coke County, Texas.
All three properties are used for the storage of tubulars and production
equipment. We also own 19 vehicles which are used in the field by employees. We
own 2 workover rigs, which are used for servicing our wells.
LITIGATION
In 2001, Abraxas and Abraxas Wamsutter L.P. were named as defendants
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 Abraxas and
Abraxas Wamsutter, L.P. related to the responsibility for year 2000 ad valorem
taxes on crude oil and natural gas properties sold by Abraxas and Abraxas
Wamsutter, L.P. 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. Abraxas has filed an appeal. We believe these charges are without
merit. We have established a reserve in the amount of $845,000, which represents
our estimated share of the judgment.
In late 2000, Abraxas received a Final De Minimis Settlement Offer
from the United States Environmental Protection Agency concerning the Casmalia
Disposal Site, Santa Barbara County, California. Abraxas' liability for the
cleanup at the Superfund site is based on a 1992 acquisition, which is alleged
to have transported or arranged for the transportation of oil field waste and
drilling muds to the Superfund site. Abraxas has engaged California counsel to
evaluate the notice of proposed de minimis settlement and its notice of
potential strict liability under the Comprehensive Environmental Response,
Compensation and Liability Act. Defense of the action is handled through a joint
group of crude oil companies, all of which are claiming a petroleum exclusion
that limits Abraxas' liability. The potential financial exposure and any
settlement posture has yet not been developed, but is considered by Abraxas to
be immaterial.
Additionally, from time to time, we are involved in litigation
relating to claims arising out of operations in the normal course of business.
At December 31, 2002, we were not engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material adverse effect on
our operations.
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS
New Grey Wolf is an Alberta corporation, certain of its officers and
directors may be residents of various jurisdictions outside the United States
and its Canadian counsel, Osler, Hoskin & Harcourt, LLP, are residents of
Canada. All or a substantial portion of the assets of New Grey Wolf and of such
persons may be located outside the United States. As a result, it may be
difficult for investors to effect service of
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process within the United States upon such persons or to enforce judgments
obtained against such persons in United States courts and predicated upon the
civil liability provisions of the Securities Act. Notwithstanding the
foregoing, New Grey Wolf has irrevocably agreed that it may be served with
process with respect to actions based on offers and sales of securities made
hereby in the United States by serving Chris E. Williford, c/o Abraxas
Petroleum Corporation, 500 North Loop 1604 East, Suite 100, San Antonio,
Texas 78232, New Grey Wolf's United States agent appointed for that purpose.
New Grey Wolf has been advised by its Canadian counsel, Osler, Hoskin &
Harcourt, LLP, that there is doubt as to the enforceability in Canada against
New Grey Wolf or against any of its directors, controlling persons, officers
or experts who are not residents of the United States, in original actions
for enforcement of judgments of United States courts, of liabilities
predicated solely upon United States federal securities laws.
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MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
Set forth below are the names, ages, years of service and positions of
the executive officers and directors of Abraxas, as well as certain executive
officers of New Grey Wolf. The term of the Class I directors of Abraxas expires
in 2003, the term of the Class II directors expires in 2005 and the term of the
Class III directors expires in 2004.
<Table>
<Caption>
NAME AND MUNICIPALITY OF RESIDENCE AGE OFFICE CLASS
Robert L. G. Watson, Chairman of the Board, President and Chief
San Antonio, Texas.......................... 52 Executive Officer III
Chris E. Williford, Executive Vice President, Chief Financial
San Antonio, Texas.......................... 52 Officer and Treasurer --
Robert W. Carington, Jr.,
San Antonio, Texas.......................... 42 Executive Vice President --
Craig S. Bartlett, Jr.,
Montclair, New Jersey....................... 69 Director II
Franklin A. Burke,
Doyleston, Pennsylvania..................... 69 Director I
Ralph F. Cox,
Ft. Worth, Texas............................ 70 Director II
Dennis E. Logue
Norman, Oklahoma............................ 59 Director II
James C. Phelps,
San Antonio, Texas.......................... 80 Director III
Joseph A. Wagda,
Danville, California........................ 59 Director II
</Table>
ROBERT L. G. WATSON has served as Chairman of the Board, President,
Chief Executive Officer and a director of Abraxas since 1977. From May 1996 to
January 2003, Mr. Watson also served as Chairman of the Board and a director of
Old Grey Wolf. Since January 2003, he has served as Chairman of the Board and a
director of New Grey Wolf. In November 1996, Mr. Watson was elected Chairman of
the Board, President and as a director of Canadian Abraxas, a former wholly
owned Canadian subsidiary of Abraxas. Prior to joining Abraxas, Mr. Watson was
employed in various petroleum engineering positions with Tesoro Petroleum
Corporation, a crude oil and natural gas exploration and production company,
from 1972 through 1977, and DeGolyer and MacNaughton, an independent petroleum
engineering firm, from 1970 to 1972. Mr. Watson received a Bachelor of Science
degree in Mechanical Engineering from Southern Methodist University in 1972 and
a Master of Business Administration degree from the University of Texas at San
Antonio in 1974.
CHRIS E. WILLIFORD was elected Vice President, Treasurer and Chief
Financial Officer of Abraxas in January 1993, and as Executive Vice President
and a director of Abraxas in May 1993. In November 1996, Mr. Williford was
elected Vice President and Assistant Secretary of Canadian Abraxas. In December
1999, Mr. Williford resigned as a director of Abraxas. Prior to joining Abraxas,
Mr. Williford was Chief Financial Officer of American Natural Energy
Corporation, a crude oil and natural gas exploration and production company,
from July 1989 to December 1992 and President of Clark Resources Corp., a crude
oil and natural gas exploration and production company, from January 1987 to May
1989. Mr. Williford received a Bachelor of Science degree in Business
Administration from Pittsburgh State University in 1973.
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ROBERT W. CARINGTON, JR. was elected Executive Vice President and a
director of Abraxas in July 1998. In December 1999, Mr. Carington resigned as a
director of Abraxas. Prior to joining Abraxas, Mr. Carington was a Managing
Director with Jefferies & Company, Inc. Prior to joining Jefferies & Company,
Inc. in January 1993, Mr. Carington was a Vice President at Howard, Weil,
Labouisse, Friedrichs, Inc. Prior to joining Howard, Weil, Labouisse,
Friedrichs, Inc., Mr. Carington was a petroleum engineer with Unocal Corporation
from 1983 to 1990. Mr. Carington received a Bachelor of Science in Mechanical
Engineering from Rice University in 1983 and a Masters of Business
Administration from the University of Houston in 1990.
CRAIG S. BARTLETT JR., a director of Abraxas since December 1999, has
over forty years of commercial banking experience, the most recent being with
National Westminster Bank USA, rising to the position of Executive Vice
President, Senior Lending Officer and Chairman of the Credit Policy Committee.
Mr. Bartlett currently serves on the boards of NVR, Inc. and Janus Hotels and
Resorts, Inc. and is active in securities arbitration. Mr. Bartlett attended
Princeton University, and has a certificate in Advanced Management from
Pennsylvania State University.
FRANKLIN A. BURKE, a director of Abraxas since June 1992, has served
as President and Treasurer of Venture Securities Corporation since 1971, where
he is in charge of research and portfolio management. He has also been a general
partner and director of Burke, Lawton, Brewer & Burke, a securities brokerage
firm, since 1964, where he is responsible for research and portfolio management.
Mr. Burke also serves as a director of Suburban Community Bank in Chalfont,
Pennsylvania. Mr. Burke received a Bachelor of Science degree in Finance from
Kansas State University in 1955, a Master's degree in Finance from University of
Colorado in 1960 and studied at the graduate level at the London School of
Economics from 1962 to 1963.
RALPH F. COX, a director of Abraxas since December 1999, has over 45
years of oil and gas industry experience, over thirty of which was with Arco.
Mr. Cox retired from Arco in 1985 after having become Vice Chairman. Mr. Cox
then joined what was known as Union Pacific Resources prior to its acquisition
by Anadarko Petroleum in July 2000, retiring in 1989 as President and Chief
Operating Officer. Mr. Cox then joined Greenhill Petroleum Corporation as
President until leaving in 1994 to pursue his consulting business. Mr. Cox has
in the past and continues to serve on many boards including CH2M Hill Companies,
and is a trustee for the Fidelity group of funds. Mr. Cox earned Petroleum and
Mechanical Engineering degrees from Texas A&M University with advanced studies
at Emory University.
DENNIS E. LOGUE, a director of Abraxas since April 2003, is Dean and
Fred E. Brown Chair at the Michael F. Price College of business at the
University of Oklahoma. Prior to joining Price College in 2001, he was the
Steven Roth Professor at the Amos Tuck School at Dartmouth Collage where he had
been since 1974. He is currently a director of Sallie Mae (GSE) and Waddell &
Reed Financial, Inc. He is also on the editorial boards of several scholarly
journals, including the Journal of Banking and Finance, the Journal of Portfolio
Management, and the Journal of Management Strategy Education. Mr. Logue holds
degrees from Fordham College, Rutgers, and Cornell University.
JAMES C. PHELPS, a director of Abraxas since December 1983, has been a
consultant to crude oil and natural gas exploration and production companies
such as Panhandle Producing Company and Tesoro Petroleum Corporation since April
1981. Mr. Phelps served as a director of Old Grey Wolf from January 1996 to
January 2003. From April 1995 to May 1996, Mr. Phelps served as Chairman of the
Board and Chief Executive Officer of Old Grey Wolf, and from January 1996 to May
1996, he served as President of Old Grey Wolf. From March 1983 to September
1984, he served as President of Osborn Heirs Company, a privately owned crude
oil exploration and production company based in San Antonio. Mr. Phelps was
President and Chief Operating Officer of Tesoro Petroleum Corporation from 1971
to 1981 and prior to that was Senior Vice President and Assistant to the
President of Continental Oil Company. He received a Bachelor of Science degree
in Industrial Engineering and a Master of Science degree in Industrial
Engineering from Oklahoma State University.
JOSEPH A. WAGDA, a director of Abraxas since December 1999, has had a
varied twenty-five year career involving the financial and legal aspects of
private and corporate business transactions. Currently Mr. Wagda is Chairman,
Chief Executive Officer and a director of BrightStar Information Technology
Group, Inc., and is also an attorney and president of Altamont Capital
Management, Inc. Mr. Wagda's
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business expertise emphasizes special situation consulting and investing,
including involvement in distressed investments and venture capital
opportunities. Previously, Mr. Wagda was a senior managing director and
co-founder of the Price Waterhouse corporate finance practice. He also served
with the finance staff of Chevron Corporation and in the general counsel's
office at Ford Motor Company. Mr. Wagda received an undergraduate degree from
Fordham College, a Masters of Business Administration, with distinction, from
the Johnson Graduate School of Management, Cornell University, and a JD, with
honors, from Rutgers University.
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EXECUTIVE COMPENSATION
COMPENSATION SUMMARY
The following table sets forth a summary of compensation for the
fiscal years ended December 31, 2000, 2001 and 2002 paid by Abraxas to Robert
L.G. Watson, Abraxas' Chairman of the Board, President and Chief Executive
Officer, Chris E. Williford, Abraxas' Executive Vice President, Chief Financial
Officer and Treasurer, Robert W. Carington, Jr., Abraxas' Executive Vice
President, Lee T. Billingsley, Abraxas' Vice President--Exploration, and to
William H. Wallace, Abraxas' Vice President--Operations.
SUMMARY COMPENSATION TABLE
<Table>
<Caption>
LONG TERM
COMPENSATION
AWARDS - SECURITIES
UNDERLYING
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($) OPTIONS(#)
---- --------- --------
ANNUAL COMPENSATION
- -------------------------------------------------------------------------------------------------------------
Robert L. G. Watson, 2000 $ 259,615 $ 29,175 962,562(1)
Chairman of the Board, 2001 $ 259,615 $ 27,388 60,000
President and Chief Executive Officer 2002 $ 271,442 $ 24,592 90,000
- -------------------------------------------------------------------------------------------------------------
Chris E. Williford, 2000 $ 155,769 $ 17,505 392,701(1)
Executive Vice President, 2001 $ 155,769 $ 16,433 20,000
Chief Financial Officer and Treasurer 2002 $ 163,653 $ 14,848 43,000
- -------------------------------------------------------------------------------------------------------------
Robert W. Carington, Jr., 2000 $ 207,629 $ 23,340 549,456(1)
Executive Vice President 2001 $ 207,629 $ 21,910 20,000
2002 $ 215,577 $ 19,488 55,000
- -------------------------------------------------------------------------------------------------------------
Lee T. Billingsley 2000 $ 134,077 $ 22,004 97,972(1)
Vice President-- 2001 $ 134,077 $ 10,331 15,000
Exploration 2002 $ 156,885 $ 9,792 22,000
- -------------------------------------------------------------------------------------------------------------
William H. Wallace, 2000 $ 131,577 $ 9,425 97,972(1)
Vice President-- 2001 $ 131,577 $ 10,331 15,000
Operations 2002 $ 156,885 $ 9,792 22,000
- -------------------------------------------------------------------------------------------------------------
</Table>
- ----------
(1) In March 2002, each named officer voluntarily forfeited a substantial
number of options to purchase Abraxas common stock, which were issued
in 2000. The exercise price for the forfeited options was $5.03 per
share, and the named officers each forfeited the following number of
options: Mr. Watson - 842,562; Mr. Williford - 352,701; Mr. Carington
- 509,456; Mr. Billingsley - 97,972; Mr. Wallace - 97,972. See note
(1) to the Option Exercises table on page 71.
GRANTS OF STOCK OPTIONS AND STOCK APPRECIATION RIGHTS DURING THE FISCAL YEAR
ENDED DECEMBER 31, 2002
Pursuant to the Abraxas Petroleum Corporation 1984 Incentive Stock
Option Plan (the "ISO Plan"), the Abraxas Petroleum Corporation 1993 Key
Contributor Stock Option Plan (the "1993 Plan"), and the Abraxas Petroleum
Corporation 1994 Long Term Incentive Plan (the "LTIP"), Abraxas grants to its
employees and officers (including its directors who are also employees)
incentive stock options and non-qualified stock options. The ISO Plan, the 1993
Plan, and the LTIP are administered by the Compensation Committee which, based
upon the recommendation of the Chief Executive Officer, determines the number of
shares subject to each option.
The table below contains certain information concerning stock options
granted to Messrs. Watson, Williford, Carington and Wallace and Dr. Billingsley
during 2002:
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OPTION GRANTS IN FISCAL YEAR
<Table>
<Caption>
POTENTIAL REALIZABLE
NUMBER OF VALUE AT ASSUMED
SECURITIES EXERCISE ANNUAL RATES OF
UNDERLYING % OF TOTAL PRICE PER STOCK
OPTIONS OPTIONS SHARE PRICE APPRECIATION
GRANTED GRANTED TO (PRICE AT EXPIRATION FOR
NAME (1) EMPLOYEES GRANT) DATE OPTION TERM
----------------------
5% 10%
- -------------------------------------------------------------------------------------------------------------
Robert L.G. Watson............ 90,000 17.2 $ 0.65 11/22/12 $ 36,900 $ 93,600
- -------------------------------------------------------------------------------------------------------------
Chris E. Williford............ 43,000 8.2 $ 0.65 11/22/12 $ 17,630 $ 44,720
- -------------------------------------------------------------------------------------------------------------
Robert W. Carington, Jr....... 55,000 10.5 $ 0.65 11/22/12 $ 22,550 $ 57,200
- -------------------------------------------------------------------------------------------------------------
Lee T. Billingsley............ 22,000 4.2 $ 0.65 11/22/12 $ 9,020 $ 22,880
- -------------------------------------------------------------------------------------------------------------
William H. Wallace............ 22,000 4.2 $ 0.65 11/22/12 $ 9,020 $ 22,880
- -------------------------------------------------------------------------------------------------------------
</Table>
- ----------
(1) One-fourth of the options become exercisable on each of the first
four anniversaries of the date of grant.
AGGREGATED OPTION EXERCISES IN FISCAL 2002 AND FISCAL YEAR END OPTION VALUES
The table below contains certain information concerning exercises of
stock options during the fiscal year ended December 31, 2002, by Messrs. Watson,
Williford, Carington and Wallace and Dr. Billingsley and the fiscal year end
value of unexercised options held by Messrs. Watson, Williford, Carington and
Wallace and Dr. Billingsley. Effective January 23, 2003, the Abraxas Board of
Directors approved a reduction in the exercise price to $0.66 per share of
one-half of all options to purchase Abraxas common stock held by Mr. Watson
(320,282 options), and a reduction in the exercise price of all of stock options
previously issued to other Abraxas employees (approximately 1.8 million
options).
OPTION EXERCISES IN FISCAL YEAR
<Table>
<Caption>
VALUE OF UNEXERCISED
SHARES VALUE NUMBER OF UNEXERCISED OPTIONS OPTIONS ON DECEMBER 31,
ACQUIRED BY REALIZED ON DECEMBER 31, 2002(#) 2002 ($)
NAME EXERCISE(#) ($) EXERCISABLE/UNEXERCISABLE(1) EXERCISABLE/UNEXERCISABLE
- ------------------------------------------------------------------------------------------------------------------------
Robert L. G. Watson.......... 0 0 521,240/205,285 0/0
- ------------------------------------------------------------------------------------------------------------------------
Chris E. Williford........... 0 0 180,000/78,000 0/0
- ------------------------------------------------------------------------------------------------------------------------
Robert W. Carington, Jr...... 0 0 345,000/90,000 0/0
- ------------------------------------------------------------------------------------------------------------------------
Lee T. Billingsley........... 0 0 84,250/40,750 0/0
- ------------------------------------------------------------------------------------------------------------------------
William H. Wallace........... 0 0 46,750/40,750 0/0
- ------------------------------------------------------------------------------------------------------------------------
</Table>
- ----------------------
(1) In March 2002, a significant number of stock options granted in 2000
were voluntarily forfeited by the named officers. All forfeited
options had an exercise price in excess of the market price on the
date of forfeiture. Such forfeitures reduced the total number of
exercisable/unexercisable options held by each named officer to the
following at the forfeiture date: Mr. Watson--464,435/176,128;
Mr. Williford - 160,000/55,000; Mr. Carington - 250,000/130,000;
Mr. Billingsley - 58,500/44,500; Mr. Wallace - 32,375/33,125.
EMPLOYMENT AGREEMENTS
Abraxas has entered into employment agreements with each of Messrs.
Watson, Williford, Carington and Wallace and with Dr. Billingsley pursuant to
which each of Messrs. Watson, Williford, Carington and Wallace and Dr.
Billingsley will receive compensation as determined from time to time by the
board in its sole discretion.
The employment agreements for Messrs. Watson, Williford, and Carington
are scheduled to terminate on December 21, 2003, and shall be automatically
extended for additional one-year terms unless Abraxas gives the officer 120 days
notice prior to the expiration of the original term or any extension thereof of
its intention not to renew the employment agreement. If, during the term of the
employment agreements for each of such officers, the officer's employment is
terminated by Abraxas other than for cause or disability, by the officer other
than by reason of such officer's death or retirement, or by the officer, for
"good reason" (as defined in each officer's respective employment agreement),
then such officer
72
<Page>
will be entitled to receive a lump sum payment equal to the greater of (a) his
annual base salary for the last full year during which he was employed by
Abraxas or (b) his annual base salary for the remainder of the term of each of
their respective employment agreements.
If a change of control occurs during the term of the employment
agreement for Mr. Watson, Mr. Williford or Mr. Carington, and if subsequent to
such change of control, such officer's employment is terminated by Abraxas other
than for cause or disability, by reason of the officer's death or retirement or
by such officer, for good reason, then such officer will be entitled to the
following, as applicable:
MR. WATSON:
(1) if such termination occurs prior to the end of the first
year of the initial term of his employment agreement, a lump sum
payment equal to five times his annual base salary;
(2) if such termination occurs after the end of the first
year of the initial term of his employment agreement but prior to
the end of the second year of the initial term of his employment
agreement, a lump sum payment equal to four times his annual base
salary;
(3) if such termination occurs after the end of the second
year of the initial term of his employment agreement but prior to
the end of the third year of the initial term of his employment
agreement, a lump sum payment equal to three times his annual
base salary; and
(4) if such termination occurs after the end of the third
year of the initial term of his employment agreement a lump sum
payment equal to 2.99 times his annual base salary.
MR. WILLIFORD OR MR. CARINGTON:
(1) if such termination occurs prior to the end of the first
year of the initial term of the officer's employment agreement, a
lump sum payment equal to four times the officer's annual base
salary;
(2) if such termination occurs after the end of the first
year of the initial term of the officer's employment agreement
but prior to the end of the second year of the initial term of
the employment agreement, a lump sum payment equal to three times
the officer's annual base salary; and
(3) if such termination occurs after the end of the second
year of the initial term of the officer's employment agreement, a
lump sum payment equal to 2.99 times the officer's annual base
salary.
Abraxas has entered into employment agreements with Mr. Wallace and
Dr. Billingsley pursuant to which each of Mr. Wallace and Dr. Billingsley will
receive compensation as determined from time to time by the board in its sole
discretion. The employment agreements, originally scheduled to terminate on
December 31, 1998 for Dr. Billingsley and December 31, 2000 for Mr. Wallace,
were automatically extended and will terminate on December 31, 2003, and may be
automatically extended for an additional year if by December 1 of the prior year
neither Abraxas nor Mr. Wallace or Dr. Billingsley, as the case may be, has
given notice to the contrary. Except in the event of a change in control, at all
times during the term of the employment agreements, each of Mr. Wallace's and
Dr. Billingsley's employment is at will and may be terminated by Abraxas for any
reason without notice or cause. If a change in control occurs during the term of
the employment agreement or any extension thereof, the expiration date of Mr.
Wallace's and Dr. Billingsley's employment agreement is automatically extended
to a date no earlier than three years following the effective date of such
change in control. If, following a change in control, either Mr. Wallace's or
Dr. Billingsley's employment is terminated other than for Cause (as defined in
each of the employment agreements) or Disability (as defined in each of the
Employment Agreements), by reason of Mr. Wallace's or Dr. Billingsley's death or
retirement or by Mr. Wallace or Dr. Billingsley, as the case may be, for Good
Reason (as defined in each of the employment agreements), then the terminated
officer will be entitled to receive a lump sum payment equal to three times his
annual base salary.
73
<Page>
If any lump sum payment to Messrs. Watson, Williford, Carington,
Wallace or Dr. Billingsley would individually or together with any other amounts
paid or payable constitute an "excess parachute payment" within the meaning of
Section 280G of the Internal Revenue Code of 1986, as amended, and applicable
regulations there under, the amounts to be paid will be increased so that
Messrs. Watson, Williford, Carington, Wallace or Dr. Billingsley, as the case
may be, will be entitled to receive the amount of compensation provided in his
contract after payment of the tax imposed by Section 280G.
COMPENSATION OF DIRECTORS
NON-QUALIFIED STOCK OPTION PLAN. Messrs. Burke and Phelps have
previously been granted options to purchase 8,900 shares of common stock under
the Abraxas 1984 Non-Qualified Stock Option Plan (the "Non-Qualified Plan").
There are currently outstanding options to purchase 8,900 shares of Abraxas
common stock under the Non-Qualified Plan. Mr. Burke holds an option to purchase
8,900 Abraxas shares of common stock at an exercise price of $2.06 per share.
STOCK OPTIONS. In 1999, each of Messrs. Bartlett, Cox and Wagda were
each granted options to purchase 75,000 shares of common stock at an exercise
price of $0.98 per share.
OTHER COMPENSATION. During 2002, each director who was not an employee
of Abraxas or its affiliates, received an annual fee of $8,000 plus $1,000 for
each board meeting attended and $500 for each committee meeting attended.
Aggregate fees paid to directors in 2002 were $131,500. Except for the
foregoing, the directors of Abraxas received no other compensation for services
as directors, except for reimbursement of travel expenses to attend board
meetings.
CERTAIN TRANSACTIONS
Wind River Resources Corporation ("Wind River"), all of the capital
stock of which is owned by Mr. Watson, previously owned a twin-engine
airplane. The airplane was available for business use by employees of Abraxas
from time to time at Wind River's cost. Abraxas paid Wind River a total of
$345,000 for use of the plane during 2002. In July 2003, the airplane was
sold to a third party. In connection with the sale, Abraxas acquired Wind
River from Mr. Watson in consideration of the issuance of 106,977 shares of
Abraxas common stock and the payment of $35,000. Wind River was subsequently
dissolved.
Abraxas has adopted a policy that transactions, including loans,
between Abraxas and its officers, directors, principal stockholders, or
affiliates of any of them, will be on terms no less favorable to Abraxas than
can be obtained on an arm's length basis in transactions with third parties and
must be approved by the vote of at least a majority of the disinterested
directors.
74
<Page>
PRINCIPAL STOCKHOLDERS
Based upon information received from the persons concerned, each
person known to Abraxas to be the beneficial owner of more than five percent of
the outstanding shares of common stock of Abraxas, each director and nominee for
director, each of the named executive officers and all directors and officers of
Abraxas as a group, owned beneficially as of March 31, 2003, the number and
percentage of outstanding shares of common stock of Abraxas indicated in the
following table:
<Table>
<Caption>
NAME AND ADDRESS OF BENEFICIAL OWNER NUMBER OF SHARES (1) PERCENTAGE (%)
Venture Securities Corp.
516 N. Bethlehem Pike
Spring House, PA 19477 2,274,740(2) 6.38
Peter S. Lynch
82 Devonshire St. 58A
Boston, MA 02109 2,873,000 8.06
Robert L. G. Watson 934,195(3) 2.58
Franklin A. Burke 1,713,720(4) 4.81
James C. Phelps 539,749(5) 1.51
Chris E. Williford 203,003(6) *
Lee T. Billingsley 159,425(7) *
Robert W. Carington, Jr. 443,340(8) 1.23
William H. Wallace 51,775(9) *
C. Scott Bartlett, Jr. 87,000(10) *
Ralph F. Cox 335,000(10) *
Joseph A. Wagda 75,000(10) *
All Officers and Directors as a Group (10 persons) 4,542,207 12.25
(3)(4)(5)(6)(7)(8)(9)(10)
</Table>
- ------------------
* Less than 1%
(1) Unless otherwise indicated, all shares are held directly with sole
voting and investment power.
(2) Includes 1,188,154 shares with sole voting power held by Venture
Securities and Franklin A. Burke, a director of Abraxas, the sole
owner of Venture Securities, and 1,038,536 shares managed by Venture
Securities on behalf of third parties.
(3) Includes 41,353 shares issuable upon exercise of options granted
pursuant to Abraxas Petroleum Corporation 1993 Key Contributor Stock
Option Plan, 479,887 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive
Plan and 300 shares in a retirement account. Does not include a total
of 75,880 shares owned by the Robert L. G. Watson, Jr. Trust and the
Carey B. Watson Trust, the trustees of which are Mr. Watson's brothers
and the beneficiaries of which are Mr. Watson's children. Mr. Watson
disclaims beneficial ownership of the shares owned by these trusts.
(4) Includes 25,750 shares issuable upon exercise of options granted
pursuant to the Amended and Restated Director Stock Option Plan (the
"Director Option Plan").
(5) Includes 340,000 shares owned by Marie Phelps, Mr. Phelps' wife,
88,762 shares owned by JMRR LP, 2,000 shares issuable upon exercise of
options granted pursuant to an option agreement and 25,750 shares
issuable upon exercise of options granted pursuant to the Director
Option Plan.
(6) Includes 1,786 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1984 Incentive Stock
Option Plan, 18,214 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1993 Key Contributor
Stock Option Plan and 160,000 shares issuable upon exercise of options
granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term
Incentive Plan.
(7) Includes 62,250 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive
Plan and 5,000 shares in a retirement account.
(8) Includes 345,000 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive
Plan.
(9) Includes 46,750 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive
Plan.
(10) Includes 75,000 shares issuable upon exercise of certain option
agreements.
75
<Page>
SELLING SECURITY HOLDERS
The notes and shares of common stock are being offered by the selling
security holders listed in the table below or referred to in a prospectus
supplement. The shares of common stock and $109,523,000 principal amount of
notes being offered were issued in connection with an overall financial
restructuring through a private exchange offer exempt from, or not subject to,
the registration requirements of the Securities Act. Since the restructuring,
additional notes being offered hereunder were issued to selling security holders
in lieu of cash interest payments. The remaining 950,000 shares of common stock
represent shares underlying outstanding warrants. The selling security holders
may offer and sell, from time to time, any or all of their common stock or
notes, including any notes issued in lieu of cash interest payements.
No offer or sale under this prospectus may be made by a holder of the
securities unless that holder is listed in the table in this prospectus or until
that holder has notified us and a supplement to this prospectus has been filed
or an amendment to the related registration statement has become effective. We
will supplement or amend this prospectus to include additional selling security
holders upon request and upon provision of all required information to us.
The following table sets forth, as of April 23, 2003 (unless
subsequent information has been provided to us in writing from the selling
security holders), the name, principal amount of notes, and number of shares
received in the exchange offer by the selling security holders eligible to sell
the notes or common stock. Based on information provided to us by the selling
security holders, the table also discloses whether any selling security holder
selling in connection with the prospectus or prospectus supplement has held any
position or office with, been employed by, or otherwise has had a material
relationship with us or any of our affiliates during the three years prior to
the date of the prospectus or prospectus supplement. The selling security
holders may sell under this prospectus up to the number of shares and the
principal amount of notes indicated below, in addition to any notes issued to
the selling security holders in lieu of cash interest payments.
<Table>
<Caption>
NUMBER OF SHARES
PRINCIPAL AMOUNT OF OF COMMON
NOTES THAT MAY BE STOCK THAT MATERIAL
NAME SOLD HEREBY ($) MAY BE SOLD HEREBY RELATIONSHIP
---- ------------------- ------------------ ------------
ABN Amro Inc .............................. 2,890,000 148,605 None
Ahab International Ltd .................... 244,000 12,544 None
Ahab Partners LP .......................... 366,000 18,816 None
Basil Street Company ...................... 0 750,000 None
BBH Broad Market Fixed Fund ............... 268,000 13,798 None
BBH High Yield Fixed Income Fund .......... 835,000 42,963 None
Cathy A. Wichert Trustee .................. 60,000 3,136 None
Cebron Family Trust ....................... 27,000 1,411 None
Charles Schwab & Co. Inc .................. 21,000 1,097 None
Concordian Partners ....................... 1,830,000 94,080 None
Claire E. Fox.............................. 89,000 0 None
Credit Suisse First Boston ................ 11,586,000 595,651 None
Craig Kaplan Irrevocable Trust
David A Kaplan & Samuel Kaplan TR UA....... 6,000 0 None
David H. Vahlsing IRA #2
FCC as Custodian........................... 3,000 0 None
David Hilty ............................... 55,000 2,871 None
David Stein IRA Bear Stearns
Fee. Corp Cust ............................ 4,000 219 None
Dean Witter Reynolds ...................... 30,000 1,568 None
Deborah Z. Corson Family Trust ............ 15,000 784 None
Delaware Charter Guar & Trust TTEE FBO
Eileen P. May ............................. 7,000 376 None
</Table>
76
<Page>
<Table>
<Caption>
NUMBER OF SHARES
PRINCIPAL AMOUNT OF OF COMMON
NOTES THAT MAY BE STOCK THAT MATERIAL
NAME SOLD HEREBY ($) MAY BE SOLD HEREBY RELATIONSHIP
---- ------------------- ------------------ ------------
Delaware Charter Guar & Trust TTEE Rhonda
J. Keefer IRA.............................. 3,000 0 None
Deutsche Bank Securities .................. 305,000 15,680 None
Doris M. Clarke IRA
FCC as Custodian........................... 7,000 0 None
Embassy & Co .............................. 1,387,000 71,344 None
EV Emerald US High Yield Fund ............. 771,000 39,670 None
First Clearing Corp........................ 2,888,000 170,635 (1)
Fishingboat & Co .......................... 305,000 15,680 None
Frank Parmet & Nancy M. Parmet
JTWROS..................................... 3,000 0 None
Franklin A. Burke
TR UA Marion J Hill-Kelly Trust............ 25,000 0 None
George G. Steele III IRA
FCC as Custodian........................... 3,000 0 None
Goldman Sachs ............................. 1,169,000 60,117 None
Gryphon Hidden Values L.P.................. (2) 26,335 None
Gryphon Hidden Values Ltd.................. (2) 186,599 None
Gryphon Hidden Values 2000................. (2) 324,507 None
Halcyon Fund, L.P. and related funds....... (3) (3) None
Hare & Co ................................. 15,304,000 786,885 None
Harriett L. Manning ....................... 6,000 313 None
Harry John Cornbleet ...................... 15,000 784 None
Houlihan Lokey Howard Zukin Capital Inc.... 523,000 26,938 None
Hugo Ciccotosto IRA
FCC as Custodian........................... 6,000 0 None
Ingalls & Snyder LLC ...................... 27,599,870 994,122 None
Irenc S. Zorensky Family Trust ............ 15,000 784 None
Irwin Gold ................................ 156,000 8,022 None
Jacqueline Heffernen
IRA FCC as Custodian....................... 3,000 0 None
Jane Baker Macpherson Trustee Carington
2503 (C) Childrens......................... 40,000 2,068 (4)
Janet A. Lawton IRA
FCC as Custodian........................... 6,000 0 None
Jeff Werbalowsky .......................... 156,000 8,022 None
Jesup & Lamont Holdings, TNC, Inc. and
Charles K. Butler.......................... 0 200,000 None
JMB Capital Partners LP ................... 3,050,000 156,800 None
JoAnne Tauber IRA
FCC as Custodian........................... 3,000 0 None
John L. and Dorothy F. Greenly Jr. JT Ten.. 6,000 0 None
John S. Ingrilli And Janc Ann Ingrilli Jt 12,000 627 None
Wros ......................................
Joseph R. and Nancy C. Hafner, Jr. JT Ten.. 3,000 0 None
Joseph Manning Jr ......................... 9,000 470 None
Joseph O. Supper IRA
FCC as Custodian........................... 15,000 0 None
JP Morgan ................................. 1,067,000 54,880 None
Karl L. and Betty J. Henning JT Ten........ 5,000 0 None
Lami Trading Company ...................... 3,050,000 156,800 None
Linda Harrington IRA
FCC as Custodian........................... 6,000 0 None
Lonestar Partners LP ...................... 1,662,000 85,456 None
</Table>
77
<Page>
<Table>
<Caption>
NUMBER OF SHARES
PRINCIPAL AMOUNT OF OF COMMON
NOTES THAT MAY BE STOCK THAT MATERIAL
NAME SOLD HEREBY ($) MAY BE SOLD HEREBY RELATIONSHIP
---- ------------------- ------------------ ------------
Margaret G. Nuttycombe IRA
FCC as Custodian........................... 3,000 0 None
Mark Grasmeder SEP IRA
FCC as Custodian........................... 3,000 0 None
Martin H. Orliner Trustee, ................ 30,000 1,568 None
Mary E Edwards ............................ 30,000 1,568 None
Maryjo Simjian Garre Trustee .............. 15,000 784 None
Merrill Lynch Professional CC ............. 23,954,000 1,232,038 None
Merrill Lynch, Pierce, Fenner & Smith
Incorporated............................... 2,154,000 110,855 None
Merrill Lynch, Pierce, Fenner & Smith
Incorporated............................... 101,000 0 None
Milton L. Zorensky Insurance Trust #1 ..... 12,000 627 None
Morgan Stanley & Co. Inc .................. 2,962,000 152,715 None
Morgan Stanley D W Inc .................... 3,000 156 None
Mr. Harold D. Carter IRA................... 21,000 1,097 None
Mulberry Ltd .............................. 410,000 21,109 None
Murphy & Durien ........................... 5,000 344 None
Nancy S. Nettelbladt IRA
FCC as Custodian........................... 6,000 0 None
Ned K. Ryder & Ann K. Ryder, Trustees...... 42,000 2,195 None
NFS/FMTC IRA FBO Herbert L Eisen .......... 15,000 784 None
NFS/FMTC IRA FBO R. Scott Williams ........ 61,000 3,136 None
NFS/FMTC IRA FBO Samuel Garre III ......... 15,000 784 None
Nicholas W. Iadicicco IRA
FCC as Custodian........................... 3,000 0 None
Patricia J. Silver......................... 6,000 0 None
Peter Tyler IRA R/O
FCC as Custodian........................... 3,000 0 None
Philip Lebovitz Marilyn Lebovitz .......... 15,000 784 None
Raymond Albert Wagner...................... 6,000 0 None
Recap International (BVI) Ltd ............. 796,000 40,972 None
Recap Partners LP ......................... 396,000 20,394 None
Regiment Capital Ltd ...................... 1,958,000 100,665 None
Robert W. and Joyce M. Clarke, Jr.
JT Ten..................................... 8,000 0 None
Robert A. Iadicicco IRA
FCC Custodian.............................. 6,000 0 None
Roger H. Nettelbladt IRA
FCC as Custodian........................... 3,000 0 None
Rosemary Jung ............................. 15,000 784 None
Salomon Smith Barney ...................... 15,702,000 807,360 None
Saltship & Co ............................. 115,000 5,958 None
Sis Segainterse TT LE AG .................. 152,000 7,840 None
South Lake & Co ........................... 1,342,000 68,992 None
Spindrift Investors (Bermuda), LP ......... 405,000 20,854 None
Spindrift Partners, LP .................... 406,000 20,885 None
Stanley H. Shatz Geraloine A. Shatz ....... 30,000 1,568 None
Sterneck Value & Opportunity LP ........... 97,000 5,017 None
Venezuela Recovery FD NY .................. 610,000 31,360 None
Vibration Specialty Corp................... 4,000 0 None
Zurich Institutional Benchmark ............ 240,000 12,387 None
</Table>
78
<Page>
- ----------
(1) Notes in the principal amount of $2,557,000 and 131,680 shares of
common stock beneficially owned by Franklin A. Burke, a current
director of Abraxas, are held of record by First Clearing Corporation.
(2) Notes in the aggregate principal amount of $6,165,000 beneficially
owned by Gryphon Hidden Values, L.P., Gryphon Hidden Values, Ltd. and
Gryphon Hidden Values 2000 are held of record by Salomon Smith Barney
on their behalf.
(3) Notes in the aggregate principal amount of up to $27,457,000 and an
aggregate number of 861,053 shares of common stock beneficially owned
by Halcyon Fund, L.P. and related funds (collectively, "Halcyon") are
held of record by Merrill Lynch Professional CC and Morgan Stanley &
Co. Inc on Halcyon's behalf.
(4) Securities are held in trust on behalf of the children of Robert A.
Carington, Executive Vice President of Abraxas. Mr. Carington has
disclaimed beneficial ownership of these securities.
We prepared this table based on the information supplied to us by the
selling security holders named in the table, and we have not sought to verify
such information.
The selling security holders listed in the above table may have sold
or transferred, in transactions exempt from the registration requirements of the
Securities Act, some or all of their notes or shares of common stock since the
date on which the information in the above table was provided to us. Information
about selling security holders may change over time.
Because the selling security holders may offer all or some of their
notes or shares of common stock from time to time, we cannot estimate the amount
of notes or the number of shares of common stock that will be held by the
selling security holders upon the termination of any particular offering by such
selling security holder. Please refer to "Plan of Distribution" beginning on
page 79 of this prospectus.
79
<Page>
PLAN OF DISTRIBUTION
This prospectus covers the resale of the notes and the shares of
Abraxas common stock by the selling security holders and their donees, pledgees,
transferees or other successors in interest. The selling security holders may
sell their notes and shares of Abraxas common stock under this prospectus:
- through one or more broker-dealers acting as either
principal or agent;
- through underwriters;
- directly to investors; or
- any combination of these methods.
The selling security holders will fix a price or prices, and may
change the price, of the notes and shares of Abraxas common stock offered based
upon:
- market prices prevailing at the time of sale;
- prices related to those market prices; or
- negotiated prices.
These sales may be effected in one or more of the following
transactions (which may involve crosses and block transactions):
- on any securities exchange or U.S. inter-dealer system of a
registered national securities association on which the
common stock may be listed or quoted at the time of sale;
- in the over-the-counter market;
- in private transactions;
- through the writing of options, whether the options are
listed on an option exchange or otherwise; or
- through the settlement of short sales.
Broker-dealers, underwriters or agents may receive compensation in the
form of discounts or concessions from the selling security holders or the
purchasers. These discounts, concessions or commissions may be more than those
customary for the transaction involved. If any broker-dealer purchases the notes
or shares of common stock as principal, it may effect resales of the shares
through other broker-dealers, and other broker-dealers may receive compensation
from the purchasers for whom they act as agents.
To comply with the securities laws of some states, if applicable, the
securities may be sold in these jurisdictions only through registered or
licensed brokers or dealers. In addition, in some states the securities may not
be sold unless they have been registered or qualified for sale or an exemption
from registration or qualification requirements is available and is complied
with.
The selling security holders and any underwriters, broker-dealers or
agents that participate in the sale of the securities may be "underwriters"
within the meaning of the Securities Act. Any discounts, commissions,
concessions or profit they earn on any resale of the shares may be underwriting
discounts and commissions under the Securities Act. Any selling security holders
who are "underwriters" within the meaning of the Securities Act will be subject
to the prospectus delivery requirements of the Securities Act.
Any securities covered by this prospectus which qualify for sale under
Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule
144A rather than under this prospectus. The selling security holders may not
sell any securities described in this prospectus and may not transfer, devise or
gift these securities by other means not described in this prospectus.
To the extent required, the specific securities to be sold, the names
of the selling security holders, the respective purchase prices and public
offering prices, the names of any agent, dealer or underwriter, and
80
<Page>
any applicable commissions or discounts with respect to a particular offer will
be set forth in an accompanying prospectus supplement or, if appropriate, a
post-effective amendment to the registration statement of which this prospectus
is a part.
Under Abraxas' registration rights agreement with the selling security
holders, we have agreed to indemnify the selling security holders and each
underwriter, if any, against certain liabilities, including certain liabilities
under the Securities Act, or will contribute to payments the selling security
holders or underwriters may be required to make in respect of those liabilities.
We have agreed to pay substantially all of the expenses in connection
with the registration, offering and sale of the securities covered by this
prospectus, other than commissions, fees and discounts of underwriters, brokers,
dealers and agents.
We have agreed to keep the registration statement, of which this
prospectus is a part, effective for two years from the time this registration
statement becomes effective, subject to extension for any suspension or blackout
periods during which securities covered by this prospectus can not be sold.
81
<Page>
DESCRIPTION OF THE NOTES
Abraxas issued an aggregate principal amount of $109,706,000 of notes
on January 23, 2003 under an indenture entered into on that date among Abraxas,
the subsidiary guarantors and U.S. Bank, N.A., as trustee. The indenture is
governed by certain provisions contained in the Trust Indenture Act of 1939, as
amended. The terms of the notes include those stated in the indenture and those
made part of the indenture by reference to the Trust Indenture Act.
The indenture provides for original issuance of up to $118,250,000.00
of notes, plus such additional principal amounts as may be necessary for the
issuance of additional notes in lieu of cash interest payments. The indenture
also provides for issuance of registered exchange notes to be issued only in
exchange for a like principal amount of outstanding notes issued on January 23,
2003 and any additional notes issued in lieu of cash interest payments on such
outstanding notes. The term "notes" as used herein refers to all of the
currently outstanding notes, the exchange notes, any additional notes issued in
lieu of cash interest payments and any notes issued pursuant to the CEO Note
Options (as defined below), all of which are deemed to be a single class of
securities under the indenture for purposes of any waiver, consent or amendment.
The following description is a summary of the material provisions of
the notes, the indenture, the documents providing for the security interests of
the holders of the notes and an intercreditor and subordination agreement to
which the notes are subject. It does not restate those agreements in their
entirety. You can find definitions of certain terms used in this description
under the subheading "Certain Definitions" beginning on page 108 of this
prospectus.
BRIEF DESCRIPTION OF THE NOTES AND THE GUARANTEES
THE NOTES
The notes:
- provide that the Issuer will make current payments of
interest in cash to the extent not prohibited by the terms
of the Senior Credit Agreement or the Intercreditor
Agreement;
- provide for interest not paid in cash to be paid in the form
of additional notes;
- are general obligations of the Issuer;
- are secured by a second Lien on all of the current and
future Oil and Gas Assets of the Issuer and its
Subsidiaries, and substantially all other current and future
assets of the Issuer and its Subsidiaries;
- are subordinate to Indebtedness of Issuer under the Senior
Credit Agreementand Qualified Senior Affiliate Indebtedness
(as described under the section below entitled "Certain
Definitions"), and rank equally with all of the Issuer's
other current and future senior Indebtedness, if any;
- rank senior to all of the Issuer's current and future
Subordinated Indebtedness, if any; and
- are unconditionally guaranteed by the Subsidiary Guarantors.
THE GUARANTEES
The notes are jointly and severally guaranteed (the "Guarantees") by
all current and future Subsidiaries of the Issuer, including (but not limited
to) the following:
- Sandia;
- Wamsutter;
- Sandia Operating;
- Eastside Coal;
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- Western Associated; and
- New Grey Wolf.
The Guarantees of the notes are:
- general obligations of each current and future Subsidiary
Guarantor;
- senior in right of payment to all existing and future
Subordinated Indebtedness, if any, of each Subsidiary
Guarantor;
- subordinate to Indebtedness of each Subsidiary Guarantor
under the Senior Credit Agreement and Qualified Senior
Affiliate Indebtedness (as described under the section below
entitled "Certain Definitions"), and rank equally with all
other existing and future senior Indebtedness of each
Subsidiary Guarantor, if any;
- secured by a second lien on all of the current and future
Oil and Gas Assets of each Subsidiary Guarantor, and on
substantially all other current and future assets of each
Subsidiary Guarantor; and
- limited for each Subsidiary Guarantor to the maximum amount
which will result in each Guarantee not being a fraudulent
conveyance or fraudulent transfer.
Each Subsidiary Guarantor that makes a payment or distribution under
its Guarantee will be entitled to a contribution from each other Subsidiary
Guarantor in a prorata amount based on the net assets of each Subsidiary
Guarantor.
Each Subsidiary Guarantor may consolidate with or merge into or sell
its assets to the Issuer or another Subsidiary Guarantor that is a Wholly Owned
Subsidiary without limitation, or with or to other Persons upon the terms and
conditions set forth in the indenture. See the description of the covenant in
"Merger, Consolidation and Sale of Assets" below. In the event all of the
Capital Stock of a Subsidiary Guarantor is sold by the Issuer and/or one or more
of its Subsidiaries and the sale complies with the provisions set forth in
"Limitation on Asset Sales," such Subsidiary Guarantor's Guarantee and any
related Collateral owned by such Subsidiary Guarantor will be released.
PRINCIPAL, MATURITY AND INTEREST
The indenture provides for original issuance of up to $118,250,000.00
of notes, plus such additional principal amounts as may be necessary for the
issuance of additional notes in lieu of cash interest payments. The notes will
be issued in full registered form only, without coupons. The notes will mature
on May 1, 2007. The indenture also provides for issuance of exchange notes.
Interest on the notes accrues at the rate of 11.5% per annum and, to
the extent not prohibited by the terms of the Senior Credit Agreement or the
Intercreditor Agreement, is payable in cash semi-annually on each May 1 and
November 1, commencing on May 1, 2003, to the Persons who are registered holders
at the close of business on the April 15 and October 15 immediately preceding
the applicable interest payment date. If the payment of such interest in cash is
prohibited by the terms of the Senior Credit Agreement or the Intercreditor
Agreement, that interest will be paid in the form of notes (the "PIK notes") in
a principal amount equal to the amount of accrued and unpaid interest on the
notes plus an additional 1% per annum accrued interest for the applicable
period, on each May 1 and November 1, commencing on May 1, 2003, to the Persons
who are registered holders at the close of business on the April 15 and
October 15 immediately preceding the applicable interest payment date.
Additional interest is payable on the notes, pursuant to a
registration rights agreement, under the circumstances described in
"Registration Rights; Liquidated Damages." All references to interest in this
description include such additional interest, unless the context otherwise
requires.
Upon and during the continuation of an Event of Default, interest on
the notes will accrue at the rate of 16.5% per annum, unless the terms of the
registration rights agreement apply and provide for a higher rate of interest.
See "Registration Rights; Liquidated Damages" for a summary of the registration
rights agreement.
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Unpaid interest shall be due and payable at stated maturity or, to the
extent the notes are earlier redeemed or repurchased, on the date of such early
redemption or repurchase. Interest due and payable at the maturity of the notes
shall be paid to the Persons to whom principal is paid. Interest shall accrue
and be payable both before and after the filing of any bankruptcy petition at
the rates stated above.
Interest on the notes has been accruing from and including the issue
date of the notes. Interest is computed on the basis of a 360-day year comprised
of twelve 30-day months.
PAYING AGENT AND REGISTRAR; TRANSFER AND EXCHANGE
Initially, the Trustee is acting as registrar for the notes and as
paying agent. The notes may be presented for registration of transfer and
exchange at the office of the registrar, which currently is the Trustee's
corporate trust office at 180 East Fifth Street, Saint Paul, Minnesota 55101.
The Issuer will pay principal (and premium, if any) and interest on the notes
upon surrender of the notes at the office of the paying agent in the Borough of
Manhattan in the City of New York, State of New York. The Issuer may change the
paying agent, registrar, and the agent for service of demands and notices in
connection with the notes and the guarantees without notice to the holders of
the notes.
REDEMPTION
OPTIONAL REDEMPTION
The Issuer may redeem the 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 the Issuer redeems all or any notes,
the Issuer must also pay all interest accrued and unpaid to the applicable
redemption date. The redemption prices for the notes during the indicated time
periods are as follows:
<Table>
<Caption>
PERIOD PERCENTAGE
- ------ ----------
From January 24, 2003 to June 23, 2003........................................ 80.0429%
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%
</Table>
Notwithstanding the foregoing, the redemption price for notes to be
redeemed will in no event be less than the then current Adjusted Issued Price.
If the Issuer redeems less than all of the notes, selection of notes
for redemption will be made by the Trustee in compliance with the requirements
of the principal national securities exchange, if any, on which the notes are
listed or, if the notes are not then listed on a national securities exchange,
on a pro rata basis, by lot or by such other method as the Trustee deems fair
and appropriate. The Issuer will not redeem in part notes in principal amounts
of less than $1,000. Except as provided above, the Issuer will mail notice of
redemption at least 30 and not more than 60 days before the redemption date. The
notice will describe the amount of notes being redeemed, if less than the entire
principal amount. Interest will cease to accrue on notes which are redeemed on
the redemption date.
SECURITY
All of the Obligations of the Issuer under the notes and the indenture
and the Guarantees are secured by a second priority Lien, but subject to certain
Permitted Liens, on all of the current and future Oil and Gas Assets of the
Issuer and its Subsidiaries, and substantially all other current and future
assets of the Issuer and the Subsidiary Guarantors (other than assets securing
Acquired Indebtedness to the extent granting additional Liens would be
prohibited by the terms of the instruments relating to such Acquired
Indebtedness). The Oil and Gas Assets included in the assets that initially
secure such Obligations represent approximately 100% of the PV-10 value at June
30, 2002 attributable to Oil and Gas Assets that remain
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Property of the Issuer and its Subsidiaries after the sale of stock described
under the discussion above entitled "Business--Recent Developments--Financial
Restructuring--Sale of Stock of Canadian Abraxas and Old Grey Wolf."
If the notes become due and payable prior to maturity or are not paid
in full at maturity, the Trustee may take all actions it deems necessary or
appropriate, including, but not limited to, foreclosing upon the Collateral in
accordance with the security documents and applicable law. The right to
foreclose on the Collateral is, however, subject to certain limitations for the
benefit of the Senior Credit Facility Lenders described below under the
discussion entitled "Intercreditor Agreement." Subject to the rights of the
Senior Credit Facility Lenders and the holder of any Qualified Senior Affiliate
Indebtedness, the proceeds received from the sale of any Collateral that is the
subject of a foreclosure or collection suit will be applied first to pay the
expenses of such foreclosure or suit and amounts then payable to the Trustee,
then to pay the principal of and interest on the notes. Subject to the rights of
the Senior Credit Facility Lenders, the Trustee has the power to institute and
maintain such suits and proceedings as it may deem expedient to prevent
impairment of, or to preserve or protect its and the holders' interest in, the
Collateral.
We cannot assure you that the Trustee will be able to sell the
Collateral without substantial delays or compromises in addition to delays
resulting from limitations on the right to foreclose on the Collateral described
below under the discussion entitled "Intercreditor Agreement," or that the
proceeds obtained will be sufficient to pay all amounts owing to holders of the
notes or. You should read the discussion under the heading "Risk Factors --Risks
Related to the Offering--The security for the notes may be inadequate to satisfy
all amounts due and owing to the holders of our notes" for a further discussion
regarding the adequacy of the collateral securing the notes. Third parties that
have Permitted Liens (including, without limitation, the Senior Credit Facility
Lenders) may have rights and remedies with respect to the property subject to
such Liens that, if exercised, could adversely affect the value of the
Collateral. In addition, the ability of the holders to realize upon the
Collateral may be subject to certain bankruptcy law limitations in the event of
a bankruptcy. You should read the discussion under the heading "Risk Factors"
for more information regarding these bankruptcy law limitations.
The collateral release provisions of the indenture permit the release
of Collateral without substitution of collateral of equal value under certain
circumstances. See "Possession, Use and Release of Collateral." As described
under the summary of the covenant "Limitation on Asset Sales," the Net Cash
Proceeds of Asset Sales will be required to be utilized to Pay Down Debt.
CHANGE OF CONTROL
If a Change of Control occurs, each holder will have the right to
require that the Issuer purchase all or a portion of such holder's notes
pursuant to the offer described below (the "Change of Control Offer"), at a
purchase price equal to the percentage of the principal amount thereof then
applicable to optional redemptions by the Issuer, plus all accrued and unpaid
interest to the date of purchase.
The Issuer must mail a notice of any Change of Control to each holder
and the Trustee no later than 30 days after the Change of Control occurs. The
notice will state, among other things, the purchase date, which must be no
earlier than 30 days nor later than 45 days from the date such notice is mailed,
other than as may be required by law (the "Change of Control Payment Date"). A
Change of Control Offer must remain open for a period of 20 Business Days or
such longer period as may be required by law. Holders electing to have a note
purchased pursuant to a Change of Control Offer will be required to surrender
the note, with the form entitled "Option of Holder to Elect Purchase" on the
reverse of the note completed, to the paying agent for the notes at the address
specified in the notice prior to the close of business on the third Business Day
prior to the Change of Control Payment Date.
The Issuer will not be required to make a Change of Control Offer if a
third party makes the Change of Control Offer at the Change of Control purchase
price, at the same times and otherwise in compliance with the requirements
applicable to a Change of Control Offer made by the Issuer and purchases the
notes validly tendered and not withdrawn under such Change of Control Offer.
If a Change of Control Offer is made, there can be no assurance that
the Issuer will have available funds sufficient to pay the Change of Control
purchase price for all the notes that might be delivered by
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holders seeking to accept the Change of Control Offer. In addition, the Senior
Credit Agreement may have similar change of control provisions as the indenture,
which may further restrict the ability of the Issuer to purchase the notes.
Also, the terms of the Intercreditor Agreement will limit the Issuer's ability
to make a Change of Control Offer under certain circumstances. See the
discussion below entitled "Intercreditor Agreement." In the event the Issuer is
required to purchase notes pursuant to a Change of Control Offer, the Issuer
expects that it would seek third party financing to the extent it does not have
available funds to meet its purchase obligations. However, there can be no
assurance that the Issuer would be able to obtain such financing.
Neither the Board of Directors of the Issuer nor the Trustee may waive
the covenant relating to the Issuer's obligation to make a Change of Control
Offer. Restrictions in the indenture described in this Description of the notes
on the ability of the Issuer and its Subsidiaries to incur additional
Indebtedness, to grant liens on their property, to make Restricted Payments and
to make Asset Sales may also make more difficult or discourage a takeover of the
Issuer, whether favored or opposed by the management of the Issuer. Consummation
of any such transaction in certain circumstances may require repurchase of the
notes, and there can be no assurance that the Issuer or the acquiring party will
have sufficient financial resources to effect such repurchase. Such restrictions
and the restrictions on transactions with Affiliates may, in certain
circumstances, make more difficult or discourage any leveraged buyout of the
Issuer by the management of the Issuer. While such restrictions cover a wide
variety of arrangements which have traditionally been used to effect highly
leveraged transactions, the indenture may not afford the holders of notes
protection in all circumstances from the adverse aspects of a highly leveraged
transaction, reorganization, restructuring, merger or similar transaction.
The Issuer will comply with the requirements of Rule 14e-1 under the
Exchange Act and any other securities laws and regulations thereunder to the
extent such laws and regulations are applicable in connection with the
repurchase of notes pursuant to a Change of Control Offer. These rules require
that the Issuer keep the offer open for 20 Business Days. They also require that
the Issuer notify holders of notes of changes in the offer and extend the offer
for specified time periods if the Issuer amends the offer. If the provisions of
any securities laws or regulations conflict with the "Change of Control"
provisions in the indenture, the Issuer will comply with the applicable
securities laws and regulations and will not be deemed to have breached its
obligations under the "Change of Control" provisions of the indenture.
INTERCREDITOR AGREEMENT
The notes are subject to an intercreditor and subordination agreement.
In general, the Junior Indebtedness will be subordinated to the Senior
Indebtedness. The liens securing the Junior Indebtedness will also be
subordinated to the liens securing the Senior Indebtedness. The following
description is a summary of the material provisions of the intercreditor and
subordination agreement. It does not restate that agreement in its entirety. The
description is qualified in its entirety by the terms of the intercreditor and
subordination agreement.
The intercreditor and subordination agreement has the following
material terms:
- Upon a payment default under the Senior Credit Agreement,
the holders of the notes will not be entitled to be paid
until all Senior Indebtedness is paid in full in cash.
- Upon a default (other than a payment default) under the
Senior Credit Agreement, for a period of 180 days commencing
upon receipt by the Trustee of written notice of such
non-payment default (each a "Payment Blockage Period"), the
holders of the notes will not be entitled to be paid. There
will be at least 180 consecutive days during which no
Payment Blockage Period is in effect during any period of
365 consecutive days.
- Upon any acceleration of the Junior Indebtedness or any
payment or distribution of assets of the Issuer or any of
its Subsidiaries following a bankruptcy or insolvency
proceeding, all amounts due or to become due upon the Senior
Indebtedness shall be first paid in full in cash before any
payment is made on account of any of the Junior
Indebtedness. Following the commencement of a bankruptcy or
insolvency proceeding, any payment or distribution of assets
of the Issuer or any of its Subsidiaries to which the
holders of the notes would be entitled (excluding securities
that are subordinated to the Senior
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Indebtedness to the same extent as, or more deeply than, the
Junior Indebtedness is subordinated to the Senior
Indebtedness pursuant to the intercreditor and subordination
agreement), will be paid by the Issuer or its Subsidiaries,
or by the holders of the notes or the Trustee if received by
them or it, directly to the Senior Credit Facility Lenders
until the Senior Indebtedness is paid in full in cash.
- During a bankruptcy or insolvency proceeding, (a) the Senior
Credit Facility Lenders will be permitted to file claims and
proofs of claims in respect of the Junior Indebtedness if
there shall remain not more than 30 days before such action
is barred, prohibited or otherwise cannot be taken and (b)
the holders of the notes and the Trustee will use
commercially reasonable best efforts to take such actions as
the Senior Credit Facility Lenders may reasonably request
(at the Senior Credit Facility Lenders' expense) to collect
the Junior Indebtedness for the account of the Senior Credit
Facility Lenders and file claims or proof of claims with
respect thereto, to execute such documents or instruments to
enable the Senior Credit Facility Lenders to enforce any and
all claims and the liens and security interests securing
payment of the Junior Indebtedness and to collect and
receive for the account of the Senior Credit Facility
Lenders any and all payments or distributions which may be
payable or deliverable upon or with respect to the Junior
Indebtedness.
- Any payment or other distribution of assets of the Issuer or
any of its Subsidiaries received by the holders of the notes
or the Trustee prior to the payment in full of the Senior
Indebtedness will be held by the holders of the notes or the
Trustee, as the case may be, in trust and paid over to the
Senior Credit Facility Lenders.
- As between the Senior Credit Facility Lenders and the
holders of the notes, the liens and security interests of
the Senior Credit Facility Lenders securing the Senior
Indebtedness will be a first priority lien on and security
interest in all of the property and assets on the Issuer and
its Subsidiaries (the "Collateral") and the liens and
security interests of the holders of the notes securing the
Junior Indebtedness will be a second priority lien on and
security interest in the Collateral. Neither the holders of
the notes nor the Trustee will challenge or contest the
validity, legality, perfection, priority, availability or
enforceability of the security interests and liens of the
Senior Credit Facility Lenders upon the Collateral or seek
to have the same avoided, disallowed, set aside, or
otherwise invalidated in any judicial proceeding or
otherwise.
- Until the payment in full in cash of the Senior
Indebtedness, the Senior Credit Facility Lenders shall have
the exclusive right to exercise and enforce all privileges
and rights to the Collateral and to manage the disposition
of the Collateral and neither the holders of the notes nor
the Trustee will exercise any Secured Creditor Remedies or
commence a bankruptcy, insolvency or other proceeding
against the Issuer or any of its Subsidiaries; provided,
however, that, upon the occurrence and during an event of
default with respect to the Junior Indebtedness, commencing
180 days after receipt by the Senior Credit Facility Lenders
of written notice of such default and intention to exercise
remedies, the holders of the notes or the Trustee may
commence a bankruptcy, insolvency or other proceeding
against the Issuer or any of its Subsidiaries or exercise
any Secured Creditor Remedies unless, in the case of any
exercise of Secured Creditor Remedies, only so long as the
Senior Credit Facility Lenders are not diligently pursuing
in good faith the exercise of their Secured Creditor
Remedies, or attempting to vacate any stay of enforcement of
their liens on a material portion of the Collateral. The
holders of the notes and the Trustee will waive any and all
rights to affect the method or challenge the appropriateness
of any action by the Senior Credit Facility Lenders with
respect to the Collateral. Upon an event of default with
respect to the Senior Indebtedness, the holders of the notes
and the Trustee will, immediately upon the request of the
Senior Credit Facility Lenders, release or otherwise
terminate their liens and security interests upon the
Collateral, to permit the Senior Credit Facility Lenders or
the Issuer or its Subsidiaries (with the consent of the
Senior Credit Facility Lenders) to sell or otherwise dispose
of the Collateral to the extent the proceeds of such sale or
other disposition is used to repay in full and in cash the
Senior Indebtedness. If such sale or other disposition of
the
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Collateral by the Senior Credit Facility Lenders or the
Issuer or its Subsidiaries (with the consent of the Senior
Credit Facility Lenders) result in a surplus after the
payment in full of the Senior Indebtedness, such surplus
will be paid to the holders of the notes or the Trustee.
- The intercreditor and subordination agreement will remain
applicable if the Issuer or any of its Subsidiaries is
subject to a bankruptcy or insolvency proceeding.
- If, during a bankruptcy or insolvency proceeding of the
Issuer or any of its Subsidiaries, the Senior Credit
Facility Lenders decide to permit the use of cash collateral
or provide post-petition financing to the Issuer or any of
its Subsidiaries, the holders of the notes and the Trustee
will not object to the use of such cash collateral or
post-petition financing by the Senior Credit Facility
Lenders (or their agent), provided that (i) the holders of
the notes or the Trustee are granted the same liens and
security interests on the post-petition Collateral that may
be granted to or for the benefit of the Senior Credit
Facility Lenders (or their agent), junior only to the liens
and security interests of the Senior Credit Facility Lenders
(or their agent) and (ii) the aggregate principal amount of
pre-petition secured indebtedness together with the
aggregate principal amount of financing in such bankruptcy
or insolvency proceeding will not exceed, at the time of
determination, the sum of (a) $50 million less the aggregate
amount applied from time to time to repay the principal
amount of the Senior Indebtedness which is accompanied by a
corresponding permanent reduction of the Revolver Commitment
under the Senior Credit Agreement plus (b) (x) $15 million,
if the then applicable Revolver Commitment under the Senior
Credit Agreement is $25 million or greater, (y) $10 million,
if the then applicable Revolver Commitment under the Senior
Credit Agreement is less than $25 million and greater than
or equal to $15 million or (z) $5 million, if the then
applicable Revolver Commitment under the Senior Credit
Agreement is less than $15 million (the sum of the
immediately preceding clauses (a) and (b), the "Maximum
Senior Indebtedness"); provided, however, that in no event
shall Indebtedness constituting Bank Product Obligations or
Related Senior Indebtedness (as such terms are defined in
the Intercreditor Agreement) be included in the calculation
of Maximum Senior Indebtedness. Neither the holders of the
notes nor the Trustee will object to a motion for relief
from the automatic stay in any proceeding to foreclose on
and sell the Collateral.
- The Senior Credit Facility Lenders will have absolute power
and discretion, without notice to the holders of the notes
or the Trustee, to deal in any manner with the Senior
Indebtedness including, without limitation, amendments,
modifications, supplements, refinancings, renewals,
refundings, extensions or terminations of the documents
related to the Senior Indebtedness, provided that the Senior
Credit Facility Lenders may not (i) increase the principal
amount of the Senior Indebtedness (excluding any Related
Senior Indebtedness and Senior Indebtedness under any Bank
Product Agreement) to a principal amount in excess of the
Maximum Senior Indebtedness, less the outstanding Term Loan
under the Senior Credit Agreement or (ii) extend the final
maturity of the Senior Indebtedness beyond January 23, 2008.
Neither the holders of the notes nor the Trustee will amend,
modify or supplement any terms of the documents related to
such notes in a manner adverse to the Senior Credit Facility
Lenders without the prior written consent of the Senior
Credit Facility Lenders.
- Until the payment in full of the Senior Secured Obligations,
neither the holders of the notes nor the Trustee will cancel
or otherwise discharge any of the indebtedness evidenced by
the notes or subordinate such indebtedness to any other
indebtedness of the Issuer or any of its Subsidiaries, other
than the Senior Indebtedness.
CERTAIN DEFINITIONS WITH RESPECT TO THE INTERCREDITOR AGREEMENT
"BANK PRODUCT AGREEMENT" means any agreement for any service or
facility extended to the Issuer or any of its Subsidiaries by the Senior Credit
Facility Representative or any Senior Credit Facility Lender or any Affiliate of
the Senior Credit Facility Representative or any such lender including: (a)
credit cards, (b) credit card processing services, (c) debit cards, (d) purchase
cards, (e) cash management or related
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services (including the Automated Clearing House processing of electronic funds
transfers through the direct Federal Reserve Fedline system), (f) cash
management, including controlled disbursement, accounts or services, or (g)
Hedging Agreements.
"HEDGING AGREEMENT" means any Currency Protection Agreement (a
currency swap, cap or collar agreement or similar arrangement entered into with
the intent of protecting against fluctuations in currency values, either
generally or under specific contingencies), any Interest Rate Protection
Agreement (an interest rate swap, cap or collar agreement or similar arrangement
entered into with the intent of protecting against fluctuations in interest
rates or the exchange of notional interest obligations, either generally or
under specific contingencies), or Commodity Hedging Agreement (a commodity
hedging or purchase agreement or similar arrangement entered into with the
intent of protecting against fluctuations in commodity prices or the exchange of
notional commodity obligations, either generally or under specific
contingencies).
"JUNIOR INDEBTEDNESS" means any and all presently existing or
hereafter arising Indebtedness, claims, debts, liabilities, obligations
(including, without limitation, any prepayment premium), fees, expenses or
indemnities of the Issuer or any of its Subsidiaries owing to the holders of the
notes (or their agents or trustees) under the indenture, the notes and any other
agreement, instrument or document related thereto, whether direct or indirect,
whether contingent (including in respect of any guaranty or the registration
rights agreement) or of any other nature, character, or description (including
all interest and other amounts accruing after commencement of any bankruptcy or
insolvency proceeding, and any interest and other amounts that, but for the
provisions of the bankruptcy code, would have accrued and become due or
otherwise would have been allowed), and any refinancings, renewals, refundings,
or extensions of such amounts to the extent permitted under the Intercreditor
Agreement.
"SECURED CREDITOR REMEDIES" means any action by the Senior Credit
Facility Representative, the Senior Credit Facility Lenders, the holders of the
notes or their trustee (each a "Secured Creditor") in furtherance of the sale,
foreclosure, realization upon, or the repossession or liquidation of any of the
Collateral, including, without limitation: (i) the exercise of any remedies or
rights of a "Secured Creditor" under Article 9 of the applicable Uniform
Commercial Code, such as, without limitation, the notification of account
debtors; (ii) the exercise of any remedies or rights as a mortgagee or
beneficiary (or by the trustee on behalf of the beneficiary), including, without
limitation, the appointment of a receiver, or the commencement of any
foreclosure proceedings or the exercise of any power of sale, including, without
limitation, the placing of any advertisement for the sale of any Collateral;
(iii) the exercise of any remedies available to a judgment creditor; (iv) the
exercise of any rights of forfeiture, recession or repossession of any assets,
or (v) any other remedy available in respect of the Collateral available to such
Secured Creditor under any agreement, instrument or other document to which it
is a party or under applicable law, provided that Secured Creditor Remedies
shall not include any action taken by a Secured Creditor solely to (A) correct
any mistake or ambiguity in any agreement, instrument or other document or (B)
remedy or cure any defect in or lapse of perfection of the lien of a Secured
Creditor in the Collateral.
"SENIOR INDEBTEDNESS" means any and all presently existing or
hereafter arising indebtedness, reimbursement obligations, claims, debts,
liabilities, obligations (including, without limitation, any prepayment
premium), expenses, fees or indemnities of the Issuer or any of its Subsidiaries
owing to the Senior Credit Facility Lenders (or their agents) under the Senior
Credit Agreement or any other agreement, instrument or document related thereto
(including under any Bank Product Agreement), whether direct or indirect,
whether contingent (including in respect of any guaranty) or of any other
nature, character, or description (including all interest and other amounts
accruing after commencement of any bankruptcy or insolvency proceeding, and all
interest and other amounts that, but for the provisions of the bankruptcy code,
would have accrued and become due or otherwise would have been allowed), and any
refinancings, renewals, refundings, or, to the extent permitted in the
intercreditor and subordination agreement, extensions of such amounts.
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CERTAIN COVENANTS
The indenture contains, among others, the following covenants:
LIMITATION ON INCURRENCE OF ADDITIONAL INDEBTEDNESS
Other than Permitted Indebtedness, the Issuer may not, and may not
cause or permit any of its Subsidiaries to, directly or indirectly, create,
incur, assume, guarantee, acquire, become liable, contingently or otherwise,
with respect to, or otherwise become responsible for payment of (collectively,
"incur") any Indebtedness.
Indebtedness of a Person existing at the time such Person becomes a
Subsidiary (whether by merger, consolidation, acquisition of Capital Stock or
otherwise) or is merged with or into the Issuer or any Subsidiary or which is
secured by a Lien on an asset acquired by the Issuer or a Subsidiary (whether or
not such Indebtedness is assumed by the acquiring Person) shall be deemed
incurred at the time the Person becomes a Subsidiary or at the time of the asset
acquisition.
The Issuer will not, and will not permit any Subsidiary Guarantor, to
incur any Indebtedness which by its terms (or by the terms of any agreement
governing such Indebtedness) is subordinated in right of payment to any other
Indebtedness (other than to senior Indebtedness under the Senior Credit
Agreement and Qualified Senior Affiliate Indebtedness) of the Issuer or such
Subsidiary Guarantor unless such Indebtedness is also by its terms (or by the
terms of any agreement governing such Indebtedness) made expressly subordinate
in right of payment to the notes or the Guarantee of such Subsidiary Guarantor,
as the case may be, pursuant to subordination provisions that are substantively
identical to the subordination provisions of such Indebtedness (or such
agreement) that are most favorable to the holders of any other Indebtedness
(other than to senior Indebtedness under the Senior Credit Agreement and
Qualified Senior Affiliate Indebtedness) of the Issuer or such Subsidiary
Guarantor, as the case may be. Notwithstanding the foregoing, the provisions of
this paragraph do not prohibit tranches of Indebtedness under the Senior Credit
Agreement being subordinated to other tranches of Indebtedness under the Senior
Credit Agreement. The Issuer will not, and will not permit any Subsidiary to,
incur or suffer to exist Indebtedness that is senior in right of payment to the
notes or any Guarantee, as the case may be, and expressly contractually
subordinate in right of payment to any other Indebtedness of the Issuer or such
Subsidiary, as the case may be.
LIMITATION ON RESTRICTED PAYMENTS
The indenture defines and prohibits the following as Restricted
Payments if done by the Issuer or any of its Subsidiaries:
- declare or pay any dividend or make any distribution (other
than dividends or distributions payable solely in Qualified
Capital Stock of the Issuer) on or in respect of shares of
the Issuer's Capital Stock to holders of such Capital Stock;
- purchase, redeem or otherwise acquire or retire for value
any Capital Stock of the Issuer or any warrants, rights or
options to purchase or acquire shares of any class of such
Capital Stock other than through the exchange therefore
solely of Qualified Capital Stock of the Issuer or warrants,
rights or options to purchase or acquire shares of Qualified
Capital Stock of the Issuer;
- make any principal payment on, purchase, defease, redeem,
prepay, decrease or otherwise acquire or retire for value,
prior to any scheduled final maturity, scheduled repayment
or scheduled sinking fund payment, any Subordinated
Indebtedness of the Issuer or a Subsidiary Guarantor; or
- make any Investment (other than a Permitted Investment).
However, the Issuer may take the following actions:
- if no Default or Event of Default shall have occurred and be
continuing, the acquisition of any shares of Capital Stock
of the Issuer solely in exchange for shares of Qualified
Capital Stock of the Issuer, and
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- if no Default or Event of Default shall have occurred and be
continuing, the acquisition of any Indebtedness of the
Issuer or a Subsidiary Guarantor that is subordinate or
junior in right of payment to the notes or such Subsidiary
Guarantor's Guarantee, as the case may be, the incurrence of
which was not in violation of the indenture, solely in
exchange for shares of Qualified Capital Stock of the
Issuer.
LIMITATION ON ASSET SALES
The Issuer may not, and may not cause or permit any of its
Subsidiaries to, consummate an Asset Sale unless the consideration received is
at least equal to the fair market value of the assets sold or otherwise disposed
of, as determined in good faith by the Issuer's Board of Directors or senior
management of the Issuer, and at least 95% of the consideration received is cash
or Cash Equivalents and is received at the time of such disposition.
The Issuer will be required to apply Net Cash Proceeds received from
any Asset Sale to Pay Down Debt.
If at any time any consideration (other than cash or Cash Equivalents)
received in connection with any Asset Sale is converted into or sold or
otherwise disposed of for cash, then such conversion or disposition shall be
treated like an Asset Sale and the Net Cash Proceeds will be applied as
described above.
The Issuer may defer the action to Pay Down Debt until there is an
aggregate Available Proceeds Amount equal to or in excess of $500,000.00
resulting from one or more Asset Sales (at which time the entire unutilized
Available Proceeds Amount, and not just the amount in excess of $500,000.00,
will be applied as required pursuant to this paragraph).
All Collateral Proceeds delivered to the Trustee will constitute Trust
Moneys, and all Collateral Proceeds will be delivered by the Issuer:
- so long as any Indebtedness under the Senior Credit
Agreement or any Qualified Senior Affiliate Indebtedness
remains outstanding, to the Senior Credit Facility
Representative; and
- otherwise to the Trustee and all Collateral Proceeds
delivered to the Trustee will be deposited in the Collateral
Account in accordance with the indenture. These Collateral
Proceeds may be withdrawn from the Collateral Account for
application by the Issuer as set forth above or otherwise
pursuant to the indenture as summarized in "Deposit; Use and
Release of Trust Moneys."
In the event of the transfer of substantially all (but not all) of the
consolidated assets of the Issuer as an entirety to a Person in a transaction
permitted under the covenant described in "Merger, Consolidation and Sale of
Assets," the successor corporation will be deemed to have sold the consolidated
assets of the Issuer not so transferred and must comply with the provisions of
this covenant as if it were an Asset Sale. In addition, the fair market value of
the consolidated assets of the Issuer deemed to be sold will be deemed to be Net
Cash Proceeds.
The Issuer will comply with the requirements of Rule 14e-1 under the
Exchange Act and any other securities laws and regulations thereunder to the
extent such laws and regulations are applicable in connection with the
repurchase of notes as a result of an action to Pay Down Debt.
LIMITATION ON DIVIDEND AND OTHER PAYMENT RESTRICTIONS AFFECTING
SUBSIDIARIES
The Issuer may not, and may not cause or permit any of its
Subsidiaries to, directly or indirectly, create or otherwise cause or permit to
exist or become effective any encumbrance or restriction (each, a "Payment
Restriction") on the ability of any Subsidiary to:
- pay dividends or make any other distributions on or in
respect of its Capital Stock;
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- make loans or advances, or to pay any Indebtedness or other
obligation owed, to the Issuer or any other Subsidiary;
- guarantee any Indebtedness or any other obligation of the
Issuer or any Subsidiary; or
- transfer any of its property or assets to the Issuer or any
other Subsidiary.
The preceding will not apply, however, to encumbrances or restrictions
existing under or by reason of the following (which are excluded from the term
"Payment Restriction"):
(1) applicable law;
(2) the indenture, the Senior Credit Agreement, any security document
or any of the security documents entered into in connection with the Senior
Credit Agreement, and any document or instrument evidencing, governing or
securing any of the Qualified Senior Affiliate Indebtedness;
(3) customary non-assignment provisions of any contract or any lease
governing a leasehold interest of any Subsidiary;
(4) any instrument governing Acquired Indebtedness, which encumbrance
or restriction is not applicable to such Subsidiary, or the properties or assets
of such Subsidiary, other than the Person or the properties or assets of the
Person so acquired;
(5) agreements existing on the Issue Date to the extent and in the
manner such agreements were in effect on the Issue Date;
(6) customary restrictions with respect to a Subsidiary pursuant to an
agreement that has been entered into for the sale or disposition of Capital
Stock or assets of such Subsidiary to be consummated in accordance with the
terms of the indenture solely in respect of the assets or Capital Stock to be
sold or disposed of;
(7) any instrument governing a Permitted Lien, to the extent and only
to the extent such instrument restricts the transfer or other disposition of
assets subject to such Permitted Lien; or
(8) an agreement governing Refinancing Indebtedness incurred to
Refinance the Indebtedness issued, assumed or incurred pursuant to an agreement
referred to in clause (2), (4) or (5) above; provided, however, that the
provisions relating to such encumbrance or restriction contained in any such
Refinancing Indebtedness are no less favorable to the holders in any material
respect as determined by the Board of Directors of the Issuer in its reasonable
and good faith judgment than the provisions relating to such encumbrance or
restriction contained in the applicable agreement referred to in such clause
(2), (4) or (5).
LIMITATION ON PREFERRED STOCK OF SUBSIDIARIES
The Subsidiaries may not issue any Preferred Stock (other than to the
Issuer or to a Wholly Owned Subsidiary) or permit any Person (other than the
Issuer or a Wholly Owned Subsidiary) to own any Preferred Stock of any
Subsidiary.
LIMITATION ON LIENS
The Issuer may not, and may not cause or permit any of its
Subsidiaries to, directly or indirectly, create, incur, assume or permit or
suffer to exist or remain in effect any Liens upon any properties or assets of
the Issuer or of any of its Subsidiaries, whether owned on the Issue Date or
acquired after the Issue Date, or on any income or profits therefrom, or assign
or otherwise convey any right to receive income or profits thereon, other than
Permitted Liens.
MERGER, CONSOLIDATION AND SALE OF ASSETS
The Issuer shall not, in a single transaction or series of related
transactions;
- consolidate or merge with or into any Person,
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- or sell, assign, transfer, lease, convey or otherwise
dispose of (or cause or permit any Subsidiary to sell,
assign, transfer, lease, convey or otherwise dispose of) all
or substantially all of the assets owned directly or
indirectly by the Issuer (determined on a consolidated basis
for the Issuer and its Subsidiaries), whether as an entirety
or substantially as an entirety to any Person,
unless:
- either
(A) the Issuer shall be the surviving or continuing
corporation, or
(B) the Person (if other than the Issuer) formed by such
consolidation or into which the Issuer is merged or the Person which
acquires by sale, assignment, transfer, lease, conveyance or other
disposition the assets of the Issuer and its Subsidiaries
substantially as an entirety (the "Surviving Entity")
(i) shall be a corporation organized and validly
existing under the laws of the United States or any state thereof or
the District of Columbia; and
(ii) shall expressly assume, by supplemental indenture
(in form and substance satisfactory to the Trustee), executed and
delivered to the Trustee, the due and punctual payment of the
principal of, premium, if any, and interest on all of the notes and
the performance of every covenant of the notes, the indenture, and the
security documents on the part of the Issuer to be performed or
observed;
- immediately after giving effect to such transaction and the
assumption contemplated above (including giving effect to any
Indebtedness incurred or anticipated to be incurred and any Lien
granted in connection with or in respect of such transaction),
the Issuer or such Surviving Entity, as the case may be,
(A) shall have a Consolidated Net Worth equal to or greater
than the Consolidated Net Worth of the Issuer immediately prior to
such transaction, and
(B) both (i) the Issuer's or such Surviving Entity's
(calculated as if such Surviving Entity was the Issuer), as the case
may be, Consolidated EBITDA Coverage Ratio is at least equal to 2.5 to
1.0; and (ii) the Issuer's or such Surviving Entity's (calculated as
if such Surviving Entity was the Issuer), as the case may be, Adjusted
Consolidated Net Tangible Assets are equal to or greater than 150% of
the aggregate consolidated Indebtedness of the Issuer and its
Subsidiaries;
- immediately before and immediately after giving effect to such
transaction and the assumption contemplated above (including,
without limitation, giving effect to any Indebtedness incurred or
anticipated to be incurred and any Lien granted in connection
with or in respect of the transaction), no Default or Event of
Default shall have occurred or be continuing; and
- the Issuer or the Surviving Entity, as the case may be, shall
have delivered to the Trustee an officer's certificate and an
opinion of counsel, each stating that such consolidation, merger,
sale, assignment, transfer, lease, conveyance or other
disposition and, if a supplemental indenture is required in
connection with such transaction, such supplemental indenture
comply with the applicable provisions of the indenture and that
all conditions precedent in the indenture relating to such
transaction have been satisfied.
For purposes of the foregoing, the transfer (by lease, assignment,
sale or otherwise, in a single transaction or series of transactions) of all or
substantially all of the assets of one or more Subsidiaries the Capital Stock of
which constitutes all or substantially all of the assets of the Issuer, shall be
deemed to be the transfer of all or substantially all of the assets of the
Issuer.
Upon any consolidation or merger or any transfer of all or
substantially all of the assets of the Issuer in accordance with the foregoing,
in which the Issuer is not the continuing corporation, the successor
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Person formed by such consolidation or into which the Issuer is merged or to
which such transfer is made shall succeed to, and be substituted for, and may
exercise every right and power of, the Issuer under the indenture and the notes
and thereafter (except in the case of a lease), the Issuer will be relieved of
all further obligations and covenants under the indenture and the notes.
Each Subsidiary Guarantor (other than any Subsidiary Guarantor whose
Guarantee is to be released in accordance with the terms of the Guarantee and
the indenture in connection with any transaction complying with the provisions
of the indenture described under "Merger, Consolidation and Sale of Assets") may
not, and the Issuer may not cause or permit any Subsidiary Guarantor to,
consolidate with or merge with or into any Person other than the Issuer or
another Subsidiary Guarantor that is a Wholly Owned Subsidiary unless:
- the entity formed by or surviving any such consolidation or
merger (if other than the Subsidiary Guarantor) is a Person
organized and existing under the laws of the United States
or any state thereof or the District of Columbia (or if such
Subsidiary Guarantor was formed under the laws of Canada or
any province or territory thereof, such Surviving Entity
shall be a Person organized and validly existing under the
laws of Canada or any province or territory thereof);
- such entity assumes by execution of a supplemental indenture
all of the obligations of the Subsidiary Guarantor under its
Guarantee;
- immediately after giving effect to such transaction, no
Default or Event of Default shall have occurred and be
continuing; and
- immediately after giving effect to such transaction and the
use of any net proceeds therefrom on a pro forma basis, the
Issuer could satisfy the Consolidated Net Worth and
Consolidated EBITDA Coverage Ratio and Adjusted Consolidated
Net Tangible Assets tests set forth above.
Any merger or consolidation of a Subsidiary Guarantor with and into
the Issuer (with the Issuer being the Surviving Entity) need only comply with
the officer's certificate and opinion of counsel provisions set forth above.
LIMITATIONS ON TRANSACTIONS WITH AFFILIATES
The Issuer may not, and may not cause or permit any of its
Subsidiaries to, directly or indirectly, engage in any transaction or series of
related transactions (including, without limitation, the purchase, sale, lease
or exchange of any property, the guaranteeing of any Indebtedness or the
rendering of any service) with any of its Affiliates unless:
- such transaction or series of related transactions is not
otherwise prohibited by the terms of the indenture and is on
terms that are fair and reasonable to the Issuer or the
applicable Subsidiary and are no less favorable to the
Issuer or the applicable Subsidiary than would have been
obtained in a comparable transaction at such time on an
arm's-length basis from a Person that is not an Affiliate;
and
- with respect to a transaction or series of related
transactions involving aggregate payments or other property
with a fair market value in excess of $250,000.00, the
Issuer obtains Board approval which is evidenced by a
resolution stating that the Board has determined that such
transaction complies with the foregoing provisions.
In addition, if the transaction or series of related transactions
involves an aggregate fair market value of more than $2,000,000.00, the Issuer
must, prior to the consummation thereof, obtain a favorable opinion as to the
fairness of such transaction or series of related transactions to the Issuer or
the relevant Subsidiary, as the case may be, from a financial point of view,
from an Independent Advisor and file the same with the Trustee.
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The foregoing shall not apply to:
- reasonable fees and compensation paid to and indemnity
provided on behalf of, officers, directors, employees or
consultants of the Issuer or any Subsidiary as determined in
good faith by the Board of Directors or senior management of
the Issuer or such Subsidiary, as the case may be;
- transactions exclusively between or among the Issuer and any
of its Subsidiaries or exclusively between or among such
Subsidiaries if such transactions are not otherwise
prohibited by the indenture; and
- Restricted Payments permitted by the indenture, or any
guarantee or assumption by the Issuer or any of its
Subsidiaries of Indebtedness of the Issuer or any of its
Subsidiaries if the incurrence of such Indebtedness was not
prohibited by the indenture.
ADDITIONAL SUBSIDIARY GUARANTEES
All Subsidiaries of the Issuer shall be Subsidiary Guarantors. If any
Subsidiary of the Issuer is formed after the Issue Date, or if a Person
otherwise becomes a Subsidiary of the Issuer after the Issue Date, the Issuer
shall cause such Subsidiary to:
- execute and deliver to the Trustee a supplemental indenture
in form reasonably satisfactory to the Trustee pursuant to
which such Subsidiary shall unconditionally guarantee all of
the Issuer's obligations under the notes and the indenture
on the terms set forth in the indenture;
- grant to the Trustee a second priority Lien (subject to
certain Permitted Liens) on all of the current and future
Oil and Gas Assets of such Subsidiary, and substantially all
of its other current and future assets using applicable
security documents substantially in the same form as those
executed and delivered on January 23, 2003; and
- deliver to the Trustee an opinion of counsel and an
officers' certificate, stating that no event of default
shall occur as a result of such supplemental indenture or
security documents, that each such instrument complies with
the terms of the indenture and that each such instrument has
been duly authorized, executed and delivered by such
Subsidiary and constitutes a legal, valid, binding and
enforceable obligation of such Subsidiary.
Thereafter, such Subsidiary shall be a Subsidiary Guarantor for all
purposes of the indenture.
LIMITATION ON IMPAIRMENT OF SECURITY INTEREST
Neither the Issuer nor any of its Subsidiaries may take or omit to
take any action which would have the result of adversely affecting or impairing
the security interest in favor of the Trustee, on behalf of itself and the
holders, with respect to the Collateral, and neither the Issuer nor any of its
Subsidiaries may grant to any Person, or suffer any Person (other than the
Issuer and its Subsidiaries) to have (other than to the Trustee on behalf of the
Trustee and the holders) any interest whatsoever in the Collateral other than
Permitted Liens. Neither the Issuer nor any of its Subsidiaries may enter into
any agreement or instrument that by its terms requires the proceeds received
from any sale of Collateral to be applied to repay, redeem, defease or otherwise
acquire or retire any Indebtedness, other than Indebtedness under the Senior
Credit Agreement, Qualified Senior Affiliate Indebtedness, and the security
documents entered into in connection therewith, and other than pursuant to the
indenture and the security documents.
LIMITATION ON THE SALE OR ISSUANCE OF CAPITAL STOCK OF SUBSIDIARIES
The Issuer may not, and may not permit any Subsidiary to, sell or
otherwise dispose of any shares of Capital Stock of any Subsidiary, and shall
not permit any of its Subsidiaries, directly or indirectly, to issue or sell or
otherwise dispose of any of its Capital Stock except:
- to the Issuer or a Wholly Owned Subsidiary; or
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- if all shares of Capital Stock of such Subsidiary owned by
the Issuer and its Subsidiary are sold or otherwise disposed
of.
In connection with any sale or disposition of Capital Stock of any
Subsidiary, the Issuer will be required to comply with the covenant described
under the caption "Limitation on Asset Sales."
LIMITATION ON CONDUCT OF BUSINESS
The Issuer will not, and will not permit any of its Subsidiaries to,
engage in the conduct of any business other than the Crude Oil and Natural Gas
Business.
REPORTS TO HOLDERS
The Issuer will deliver to the Trustee within 15 days after the filing
of the same with the SEC, copies of the quarterly and annual reports and of the
information, documents and other reports, if any, which the Issuer is required
to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act.
Notwithstanding that the Issuer may not be subject to the reporting requirements
of Section 13 or 15(d) of the Exchange Act, the Issuer will file with the SEC,
to the extent permitted, and provide the Trustee and Holders with such annual
reports and such information, documents and other reports specified in Sections
13 and 15(d) of the Exchange Act. The Issuer will also comply with the other
provisions of Section 314(a) of the Trust Indenture Act.
The reports and information delivered pursuant to the preceding
paragraph shall include quarterly financials, including details regarding
sources and uses of cash or of any assets of the Issuer and its Subsidiaries.
Such financials will provide details on both a consolidated and unconsolidated
basis.
WAIVER OF STAY, EXTENSION OR USURY LAWS
The Issuer and each Subsidiary Guarantor will covenant (to the extent
that they may lawfully do so) that they will not at any time insist upon, plead,
or in any manner whatsoever claim or take the benefit or advantage of, any stay
or extension law or any usury law or other law that would prohibit or forgive
the Issuer or such Subsidiary Guarantor from paying all or any portion of the
principal of or interest on the notes as contemplated herein, wherever enacted,
now or at any time hereafter in force, or which may affect the covenants or the
performance of the indenture; and (to the extent that they may lawfully do so)
the Issuer and each Subsidiary Guarantor will expressly waive in the indenture
all benefit or advantage of any such law, and covenant that they will not
hinder, delay or impede the execution of any power herein granted to the
trustee, but will suffer and permit the execution of every such power as though
no such law had been enacted.
LEVERAGE COVENANT
The Issuer must not allow the Issuer's Consolidated EBITDA to Cash
Interest Expense Ratio, as of the last day of any calendar quarter after the
Issue Date, to be less than 3.0:1, except on the last day of the first calendar
quarter of 2003, at which time this ratio must not be less than 2.0:1.
EXCESS CASH FLOW AND EXCESS CASH
Without duplication with respect to the requirement to Pay Down Debt
set forth in the next paragraph, within 30 days after the last day of each
calendar quarter ending after the Issue Date, the Issuer must apply an amount to
Pay Down Debt equal to 90% of the Excess Cash Flow of the Issuer for such
calendar quarter.
Without duplication with respect to the requirement to Pay Down Debt
set forth in the previous paragraph, with respect to each calendar quarter
ending after the Issue Date and on the same date that the Issuer applies an
amount to Pay Down Debt pursuant to the preceding paragraph with respect to such
calendar quarter, and on a date that is 7 days after the Issue Date, the Issuer
must apply an amount to Pay Down Debt equal to all cash of the Issuer and its
Subsidiaries as of such date (each such date a "Cash Sweep Payment Date"), after
the application of an amount to Pay Down Debt pursuant to the preceding
paragraph, on that date (provided that if there is no Excess Cash Flow with
respect to such calendar quarter,
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the Cash Sweep Payment Date with respect to such calendar quarter shall be the
first business day that is 30 days after the last day of such calendar quarter),
minus
- $2.5 million,
- Restricted Cash as of such Cash Sweep Payment Date,
- the amount of Capital Expenditures the Issuer is permitted
to make pursuant to the terms of the indenture during the
next calendar quarter pursuant to the covenant described
below under the heading "Limitations on Capital
Expenditures," minus amounts available for making Capital
Expenditures under any revolving credit facility under the
Senior Credit Agreement as of such Cash Sweep Payment Date,
- cash of the Issuer as of such Cash Sweep Payment Date
otherwise applied or required to be applied to Pay Down
Debt, and
- without duplication with respect to the previous bullet
point, any such cash of the Issuer and its Subsidiaries as
of the Cash Sweep Payment Date constituting proceeds of any
equity offering by the Issuer or proceeds of any
Subordinated Indebtedness of the Issuer or any of its
Subsidiaries complying with the provisions of the indenture
described below under "Proceeds from Issuances of Equity and
Subordinated Debt."
The Issuer will manage the cash of the Issuer and its Subsidiaries in
the ordinary course of business consistent with past practices and in compliance
with the terms of the Senior Credit Agreement.
LIMITATION ON EXPENDITURES FOR SELLING, GENERAL AND ADMINISTRATIVE
EXPENSES
The Issuer must observe the following covenants with respect to
expenditures by the Issuer and its Subsidiaries on SG&A:
- The amount expended by the Issuer and its Subsidiaries on SG&A in
any calendar quarter ending after the Issue Date shall not exceed
the applicable SG&A Quarterly Amount, subject, however, to the
following carryforward and carryback provisions:
- to the extent the SG&A in any one quarter (excluding the
amount of SG&A due to any Rollover Increase because of a
prior quarter's SG&A Deficit Amount) exceeds the applicable
SG&A Quarterly Amount, the SG&A Quarterly Amount for the two
succeeding quarters shall be reduced in the aggregate by an
amount equal to the applicable SG&A Excess Amount, and
- to the extent the SG&A in any one quarter (excluding the
amount of SG&A due to any Rollover Decrease because of a
prior quarter's SG&A Excess Amount) is less than the
applicable SG&A Quarterly Amount, the SG&A Quarterly Amount
for the two succeeding quarters shall be increased in the
aggregate by an amount equal to the applicable SG&A Deficit
Amount,
- In no event shall the amount expended by the Issuer and its
Subsidiaries on SG&A in any calendar year ending after the Issue
Date exceed the SG&A Annual Amount.
LIMITATIONS ON CAPITAL EXPENDITURES
The Issuer must observe the following covenants with respect to
Capital Expenditures by the Issuer and its Subsidiaries:
- For the first calendar quarter in 2003, Capital Expenditures of
the Issuer and its Subsidiaries shall not exceed the Q1-2003
CapEx Amount, and for each other calendar quarter in 2003,
Capital Expenditures of the Issuer and its Subsidiaries shall not
exceed the Q2,3,4-2003 CapEx Amount, subject, however, to the
following carryforward and carryback provisions:
- to the extent Capital Expenditures in the first calendar
quarter of 2003 (excluding the amount of Capital
Expenditures due to any Rollover Increase because of a prior
quarter's CapEx Deficit Amount) exceed the Q1-2003 CapEx
Amount or to the extent Capital
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Expenditures in any other calendar quarter of 2003
(excluding the amount of Capital Expenditures due to any
Rollover Increase because of a prior quarter's CapEx Deficit
Amount) exceed the Q2,3,4-2003 CapEx Amount, as applicable,
the CapEx Quarterly Amount for the two succeeding quarters
shall be decreased in the aggregate by an amount equal to
the applicable CapEx Excess Amount, and
- to the extent Capital Expenditures in the first calendar
quarter of 2003 (excluding the amount of Capital
Expenditures due to any Rollover Decrease because of a prior
quarter's CapEx Excess Amount) fall below the Q1-2003 CapEx
Amount or to the extent Capital Expenditures in any other
calendar quarter of 2003 (excluding the amount of Capital
Expenditures due to any Rollover Decrease because of a prior
quarter's CapEx Excess Amount) fall below the Q2,3,4-2003
CapEx Amount, as applicable, the CapEx Quarterly Amount for
the two succeeding quarters shall be increased in the
aggregate by an amount equal to the applicable CapEx Deficit
Amount.
- In no event shall the Capital Expenditures of the Issuer and its
Subsidiaries for calendar year 2003 exceed the 2003 CapEx Amount.
- For each calendar quarter in calendar year 2004 and each calendar
quarter in any following calendar year, Capital Expenditures of
the Issuer and its Subsidiaries shall not exceed the applicable
2004-Plus CapEx Quarterly Amount, subject, however, to the
following carryforward and carryback provisions:
- to the extent Capital Expenditures in any such quarter
(excluding the amount of Capital Expenditures due to any
Rollover Increase because of a prior quarter's CapEx Deficit
Amount) exceed the applicable 2004-Plus CapEx Quarterly
Amount, the 2004-Plus CapEx Quarterly Amount for the two
succeeding quarters shall be decreased in the aggregate by
an amount equal to the applicable CapEx Excess Amount, and
- to the extent the Capital Expenditures in any such quarter
(excluding the amount of Capital Expenditures due to any
Rollover Decrease because of a prior quarter's CapEx Excess
Amount) fall below the applicable 2004-Plus CapEx Quarterly
Amount, the 2004-Plus CapEx Quarterly Amount for the two
succeeding quarters shall be increased in the aggregate by
an amount equal to the applicable CapEx Deficit Amount.
- In no event shall the Capital Expenditures of the Issuer and its
Subsidiaries for calendar year 2004 or any following calendar
year exceed the 2004-Plus CapEx Annual Amount.
With respect to the limitations on Capital Expenditures set forth
above, the Issuer will be allowed to reallocate capacity for making up to an
aggregate of $3 million of Capital Expenditures which are to be used for
satisfying capital calls with respect to non-operating mineral interests of the
Issuer and its Subsidiaries for development expenses with respect to such
non-operating mineral interests as follows:
- any such reallocation will increase the annual permissible
Capital Expenditures by the amount of such reallocation for the
calendar year to which such reallocation was made, and will
decrease the annual permissible Capital Expenditures by the
amount of such reallocation for the calendar year from which such
reallocation was made;
- the amount reallocated to a calendar year must be allocated by
the Issuer to the calendar quarters within that calendar year to
increase the permissible Capital Expenditures for such calendar
quarters, and the amount reallocated from a calendar year must be
allocated by the Issuer to the calendar quarters within that
calendar year to decrease the permissible Capital Expenditures
for such calendar quarters.
- any amount reallocated to a particular period (i.e., to a
particular calendar year or a particular calendar quarter) can be
used only for Capital Expenditures to satisfy capital calls with
respect to non-operating mineral interests of the Issuer and its
Subsidiaries for development expenses with respect to such
non-operating mineral interests
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LIMITATION ON TAX SHARING ARRANGEMENTS
Neither the Issuer nor any of its Subsidiaries may enter into any
agreement, arrangement or understanding with respect to liability for payment or
sharing of any other Person's taxes, including any tax sharing or similar
arrangement, except to the extent of any covenant pursuant to which funds or
money actually paid or transferred to or from the Issuer or its Subsidiary, as
the case may be, are thereupon actually used to pay the applicable taxes.
LIMITATION ON USES OF CASH
The indenture provides that the Issuer and its Subsidiaries will make
cash expenditures only for the following and only to the extent not otherwise
prohibited by the terms of the indenture:
- Qualified Lease Operating Costs, SG&A costs, taxes (e.g., income,
severance, ad valorem, franchise) in each case not prohibited by
the terms of the indenture;
- cash interest requirements;
- Capital Expenditures not prohibited by the terms of the
indenture;
- any oil and gas hedge settlements requiring a cash payment from
the Issuer pursuant to oil and gas hedge agreements entered into
(a) pursuant to approval by the Board of Directors of the Issuer,
(b) in the ordinary course of business, and (c) to provide
protection against oil and gas price fluctuations with respect to
reasonably anticipated oil and gas production of the Issuer and
its Subsidiaries and not for the purpose of speculating;
- any payment to reduce debt to the extent such payment is not
prohibited by the terms of the indenture, provided that the
average days outstanding for payables paid shall not be less than
the greater of (a) 45 days and (b) the industry standard
therefor, subject to adjustment by the Board of Directors of the
Issuer;
- payments due to the settling of a natural gas balancing
deficiency not to exceed $45,000 in the aggregate in any calendar
year unless a higher amount is approved by the Board of Directors
of the Issuer;
- payment of judgments rendered by a court of law;
- assessments issued by any governmental entity;
- additional cash expenditures not to exceed $2 million in the
aggregate in any calendar year; provided, however, that the
Issuer and its Subsidiaries may make aggregate cash expenditures
in excess of $2 million in any calendar year under this provision
if the Board of Directors of the Issuer approves such
expenditures;
- obligations under the Senior Credit Agreement and Qualified
Senior Affiliate Indebtedness including, but not limited to, fees
and expenses incurred in connection therewith and fees related to
any amendment, waiver, consent or similar actions taken by the
agent and lenders related thereto (the payment of which
obligations will not be prohibited by the terms of the
indenture); and
- payment of any Stark Fees.
PROCEEDS FROM ISSUANCES OF EQUITY AND SUBORDINATED DEBT
The Issuer may issue common equity, or preferred equity with
no maturity or required or allowed cash dividend, at any time and may use the
net proceeds from any such issuance in any manner consistent with other
provisions of the indenture. Such net proceeds will not be included in the
calculation of Excess Cash Flow.
The Issuer may also issue preferred equity with a maturity
or required or allowed cash dividends if such issuance complies with the
following requirements:
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- no portion of any such equity may be redeemed or repurchased
or, except as permitted pursuant to the third bullet point,
have any other cash distribution or dividend until the notes
are completely repaid,
- at least 50% of the proceeds of such issuance must
immediately be used to Pay Down Debt, and
- no cash dividends can be paid on such equity unless:
- at least 75% of such proceeds are used to Pay Down
Debt,
- the cash dividend payable to the holders of such
equity does not exceed the Cash Coupon on the
notes, and
- the holders of the notes receive in cash (in full)
current interest payments due and payable.
The Issuer and its Subsidiaries may also incur Subordinated
Indebtedness that complies with the following requirements (such Indebtedness is
referred to as "Permitted Subordinated Indebtedness"):
- no portion of any principal of any such Subordinated
Indebtedness may be repaid, or refinanced if such
refinancing results in a shorter Weighted Average Life to
Maturity or in the terms of such Subordinated Indebtedness
being less favorable to the holders of the notes, until the
notes are completely repaid,
- at least 50% of the proceeds of such issuance must
immediately be used to Pay Down Debt, and
- no cash interest can be paid on such Subordinated
Indebtedness unless:
- at least 75% of such proceeds are used to Pay Down
Debt,
- the cash portion of any interest payable to the
holders of such Subordinated Indebtedness does not
exceed the Cash Coupon on the notes, and
- the holders of the notes receive in cash (in full)
current interest payments due and payable.
ACCOUNTING
The Issuer will keep its financial accounts in accordance with GAAP
and, except as GAAP may require, consistent with past practices.
FARMOUTS
The indenture provides that the Issuer and its Subsidiaries will be
able to enter into and perform with respect to farmouts covering any of their
undeveloped wells and properties, provided that the Issuer must, prior to any
properties being transferred pursuant to such farmout, obtain written
confirmation from F. John Stark, III stating that such farmout is in the best
interests of the holders of the notes, and file the same with the Trustee,
further provided that such written confirmation will not be required for any
farmout with a farmout value (as determined as provided below) of less than
$100,000, but the total aggregate farmout value of farmouts so exempted from the
written confirmation requirement cannot exceed $500,000 in any twelve calendar
month period. For the purposes of this provision, the value of a farmout will be
the portion of the capital commitments made by the farmee(s) under the farmout
relating to the interests of the Issuer or its Subsidiaries being farmed out.
The Issuer anticipates entering into a retainer arrangement with F. John Stark,
III in connection with his services with respect to such written confirmations,
with such retainer arrangement calling for the payment to him of fees for his
services with respect to such written confirmations (the "Stark Fees"), with the
Stark Fees being excluded from the calculation of SG&A.
In addition, the indenture provides that the Issuer and its
Subsidiaries will be able to enter into and perform farmouts not complying with
the preceding paragraph if consent to such farmout is obtained from the holders
of not less than a majority of the principal amount of the then outstanding
notes issued under the indenture.
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Furthermore, the indenture provides that the farmouts referenced in
the Purchase and Sale Agreement dated November 21, 2002 between the Issuer, as
seller, and PrimeWest Gas Inc., as purchaser, as the Farmout Agreement and
included as Schedule P in such agreement, are permitted farmouts under the
indenture.
Farmouts permitted by the preceding three paragraphs are referred to
as "Permitted Farmout Agreements." The following shall apply to each Permitted
Farmout Agreement:
- the applicable portions of Liens of the security documents
securing the notes will be released with respect to the
undeveloped wells and/or properties that are subject to such
Permitted Farmout Agreement, provided that all retained interests
of the Issuer and the Subsidiaries in such wells and/or
properties will remain subject to such Liens;
- such Permitted Farmout Agreement will be deemed not to be an
Asset Sale, including, but not limited to, the purchase options
in the farmout agreements referenced above in connection with the
November 21, 2002 Purchase and Sale Agreement with PrimeWest Gas
Inc.;
- obligations of the Issuer and its Subsidiaries under such
Permitted Farmout Agreement that constitute Indebtedness will be
Permitted Indebtedness so long as any such Indebtedness is
non-recourse with respect to the Issuer and its Subsidiaries and
their properties and assets other than the wells and/or
properties that are the subject of such Permitted Farmout
Agreement; and
- to the extent such Permitted Farmout Agreement would constitute
an Investment by the Issuer or any of its Subsidiaries, such
Investment will be a Permitted Investment.
CEO NOTE OPTIONS
The Issuer may issue to its Chief Executive Officer (the "Issuer's
CEO") options to purchase notes ("CEO Note Options") as follows:
- Issuance to the Issuer's CEO on the Issue Date of options to purchase
$750,000 principal amount of notes for the market price therefor at
the Issue Date;
- Issuance to the Issuer's CEO of options to purchase $250,000 principal
amount of notes for the market price therefor at the Issue Date if the
notes trade for greater than 70% of the face amount thereof for 60
consecutive trading days, with the first of such consecutive 60 days
being in January of 2003;
- Issuance to the Issuer's CEO of options to purchase $500,000 principal
amount of notes for the market price therefor at the Issue Date if the
notes trade for greater than 70% of the face amount thereof for any 60
consecutive trading days during the first 365 calendar days after the
Issue Date; and
- Issuance to the Issuer's CEO of options to purchase $250,000 principal
amount of notes for the market price therefor at the Issue Date if the
notes trade for greater than 90% of the face amount thereof for any 60
consecutive trading days during the 365 calendar day period commencing
on the 366th day after the Issue Date, provided that if the condition
set forth in the previous bullet point is not achieved, the amount
applicable for this bulletin point shall be increased from $250,000 to
$750,000.
For determining consecutive trading days with respect to the notes, a
trading day will be a day on which there are at least $500,000 in aggregate
principal amount of notes traded and either Jefferies & Company, Inc., or its
successor, or Imperial Capital, LLC, or its successor, (as long as they did not
execute the trade) confirms to the Issuer that the trade was in the context of
the market.
LIMITATION ON ABRAXAS WAMSUTTER, LTD.
So long as the Issuer continues to have a partnership interest in
Abraxas Wamsutter, Ltd., the Issuer will not permit Abraxas Wamsutter, Ltd. to
be an operating entity.
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CONDUCT OF BUSINESS IN THE INTERIM PERIOD
The Issuer shall have conducted, and shall have caused its
Subsidiaries to conduct, business consistent with past practices during the
interim period between the date that the Offer to Exchange was made and the
Issue Date.
CALCULATION OF ORIGINAL ISSUE DISCOUNT
The Issuer will file with the Trustee promptly at the end of each
calendar year (a) a written notice specifying the amount of original issue
discount accrued on the outstanding notes as of the end of such year and (b)
such other specific information relating to such original issue discount as may
then be relevant under the Internal Revenue Code or applicable U.S. Treasury
regulation.
EVENTS OF DEFAULT
Each of the following is an "Event of Default":
- the failure to pay interest on any notes when the same becomes
due and payable;
- the failure to pay the principal on any notes, when such
principal becomes due and payable, at maturity, upon redemption
or otherwise (including the failure to make a payment to purchase
notes tendered pursuant to a Change of Control Offer or to Pay
Down Debt in connection with an Asset Sale);
- a default in the observance or performance of any other covenant
or agreement contained in the indenture which default continues
for a period of 30 days after the Issuer or any Subsidiary
Guarantor receives written notice specifying the default (and
demanding that such default be remedied) from the Trustee or the
holders of at least 25% of the outstanding principal amount of
the notes (except in the case of a default with respect to
observance or performance of any of the terms or provisions of
the covenants described above under "Change of Control" or
"Merger, Consolidation and Sale of Assets" or "Limitation on
Asset Sales" which will constitute an Event of Default with such
notice requirement but without such passage of time requirement);
- a default under any mortgage, indenture or instrument under which
there may be issued or by which there may be secured or evidenced
any Indebtedness of the Issuer or of any Subsidiary (or the
payment of which is guaranteed by the Issuer or any Subsidiary),
whether such Indebtedness now exists or is created after the
Issue Date, which default:
(A) is caused by a failure to pay principal of or premium,
if any, or interest on such Indebtedness after any
applicable grace period provided in such Indebtedness
(a "payment default"), or
(B) results in the acceleration of such Indebtedness prior
to its express maturity,
and, in each case, the principal amount of any such Indebtedness,
together with the principal amount of any other such Indebtedness
under which there has been a payment default or the maturity of
which has been so accelerated, aggregates at least $2,000,000.00;
- one or more judgments in an aggregate amount in excess of
$2,000,000.00 (unless covered by insurance by a reputable insurer
as to which the insurer has acknowledged coverage) are rendered
against the Issuer or any of its Subsidiaries and such judgments
remain undischarged, unvacated, unpaid or unstayed for a period
of 60 days after such judgment or judgments become final and
non-appealable;
- certain events of bankruptcy; or
- any of the Guarantees or any of the security documents ceases to
be in full force and effect or any of the Guarantees or any of
the security documents is declared to be null and void or invalid
and unenforceable or any of the Subsidiary Guarantors denies or
disaffirms its liability under its Guarantees (other than by
reason of release of a Subsidiary Guarantor in accordance
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with the terms of the indenture) or any obligor or any Related
Person denies or disaffirms its liability under any security
document to which it is a party.
If any Event of Default (other than the Event of Default relating to
certain events of bankruptcy) occurs and is continuing, the Trustee or the
holders of at least 25% in principal amount of outstanding notes may declare the
principal of, premium, if any, and accrued and unpaid interest on all the notes
to be due and payable by notice in writing to the Issuer and the Trustee
specifying the Event of Default and that it is a "notice of acceleration", and
the same shall become immediately due and payable. If an Event of Default
relating to certain events of bankruptcy occurs and is continuing, then all
unpaid principal of, and premium, if any, and accrued and unpaid interest on all
of the outstanding notes will be immediately due and payable without any
declaration or other act on the part of the Trustee or any holder.
After a declaration of acceleration with respect to the notes as
described in the preceding paragraph, the holders of a majority in principal
amount of the notes may rescind and cancel such declaration if:
- the rescission would not conflict with any judgment or decree;
- all existing Events of Default have been cured or waived except
nonpayment of principal or interest that has become due solely
because of such acceleration;
- to the extent the payment of such interest is lawful, interest on
overdue installments of interest and overdue principal, which has
become due otherwise than by such declaration of acceleration,
has been paid;
- the Issuer has paid the Trustee its reasonable compensation and
reimbursed the Trustee for its expenses, disbursements and
advances; and
- the Trustee shall have received an officer's certificate and an
opinion of counsel that such Event of Default has been cured or
waived in the event of the cure or waiver of an Event of Default
relating to certain events of bankruptcy.
No such rescission shall affect any subsequent Default or impair any
right consequent thereto.
Prior to the declaration of acceleration of the notes, the holders of
a majority in principal amount of the notes may waive any existing Default or
Event of Default under the indenture, and its consequences, except a default in
the payment of the principal of or interest on any notes.
Holders of the notes may not enforce the indenture or the notes except
as provided in the indenture and under the Trust Indenture Act. During the
existence of an Event of Default, the Trustee is required to exercise such
rights and powers vested in it under the indenture and use the same degree of
care and skill in its exercise thereof as a prudent man would exercise or use
under the circumstances in the conduct of his own affairs. Subject to the
provisions of the indenture relating to the duties of the Trustee, whether or
not an Event of Default shall occur and be continuing, the Trustee is under no
obligation to exercise any of its rights or powers under the indenture at the
request, order or direction of any of the holders, unless such holders have
offered to the Trustee reasonable indemnity. Subject to all provisions of the
indenture, the Intercreditor Agreement and applicable law, the holders of a
majority in aggregate principal amount of the then outstanding notes will have
the right to direct the time, method and place of conducting any proceeding for
any remedy available to the Trustee or exercising any trust or power conferred
on the Trustee.
The Issuer is required to provide an officer's certificate to the
Trustee promptly upon any such officer obtaining knowledge of any Default or
Event of Default (provided that such officers shall provide such certification
at least annually whether or not they know of any Default or Event of Default)
that has occurred and, if applicable, describe such Default or Event of Default
and the status thereof.
POSSESSION, USE AND RELEASE OF COLLATERAL
Unless an Event of Default shall have occurred and be continuing, the
Issuer and the Subsidiary Guarantors will have the right to remain in possession
and retain exclusive control of the Collateral securing the notes (other than
any cash, securities, obligations and Cash Equivalents constituting part of the
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Collateral and deposited with the Trustee in the Collateral Account or with the
Senior Credit Facility Representative and other than as set forth in the
security documents), to freely operate the Collateral and to collect, invest and
dispose of any income thereon.
RELEASE OF COLLATERAL
Upon compliance by the Issuer with the conditions set forth below in
respect of any sale, transfer or other disposition, the Trustee will release the
Released Interests (as defined below) from the Lien of the indenture and the
security documents and reconvey the Released Interests to the Issuer or the
grantor of the Lien on such property. The Issuer will have the right to obtain a
release of items of Collateral (the "Released Interests") subject to any sale,
transfer or other disposition, or owned by a Subsidiary the Capital Stock of
which is sold in compliance with the indenture such that it ceases to be a
Subsidiary, or that is the subject of a farmout allowed by the terms of the
indenture, upon compliance with the condition that the Issuer deliver to the
Trustee the following:
- a notice from the Issuer requesting the release of Released
Interests:
(A) describing the proposed Released Interests,
(B) specifying the value of such Released
Interests or such Capital Stock, as the case may be, on a
date within 60 days of the Issuer notice (the "Valuation
Date"),
(C) stating that the consideration to be received
is at least equal to the fair market value of the Released
Interests, provided that this clause (C) is not applicable
with respect to a release to be given in connection with a
farmout permitted pursuant to the indenture,
(D) stating that the release of such Released
Interests will not interfere with the Trustee's ability to
realize the value of the remaining Collateral and will not
impair the maintenance and operation of the remaining
Collateral,
(E) confirming the sale or exchange of, or an
agreement to sell or exchange, such Released Interests or
such Capital Stock, as the case may be, is a bona fide sale
to or exchange with a Person that is not an Affiliate of the
Issuer or, in the event that such sale or exchange is to or
with a Person that is an Affiliate, confirming that such
sale or exchange is made in compliance with the provisions
summarized in the description of certain covenants under
"Limitation on Transactions with Affiliates," provided that
this clause (E) is not applicable with respect to a release
to be given in connection with a farmout permitted pursuant
to the indenture,
(F) in the event there is to be a contemporaneous
substitution of property for the Collateral subject to the
sale, transfer or other disposition, specifying the property
intended to be substituted for the Collateral to be disposed
of; and
(G) with respect to a release to be given in
connection with a farmout permitted pursuant to the
indenture stating that the farmout to which the released
interests are (or are to be) subject complies with the
indenture;
- an officer's certificate of the Issuer stating that:
(A) such sale, transfer or other disposition
complies with the terms and conditions of the indenture,
including the provisions summarized in the description of
certain covenants under " Limitation on Asset Sales,"
"Limitation on Transactions with Affiliates," "Farmouts" and
"Limitation on Restricted Payments" above, to the extent any
of the foregoing are applicable,
(B) all Net Cash Proceeds from the sale, transfer
or other disposition of any of the Released Interests or
such Capital Stock, as the case may be, will be applied
pursuant to the provisions of the indenture in respect of
the deposit of proceeds into the
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Collateral Account or with the Senior Credit Facility
Representative as contemplated by the indenture and in
respect of Asset Sales, to the extent applicable, provided
that this clause (B) is not applicable with respect to a
release to be given in connection with a farmout permitted
pursuant to the indenture,
(C) there is no Default or Event of Default in
effect or continuing on the date thereof or the date of such
sale, transfer or other disposition,
(D) the release of the Collateral will not result
in a Default or Event of Default under the indenture,
(E) upon delivery of such officer's certificate,
all conditions precedent in the indenture relating to the
release in question will have been complied with,
(F) such sale, transfer or other disposition is
not between the Issuer or any Subsidiary or between
Subsidiaries, provided that this clause (F) is not
applicable with respect to a release to be given in
connection with a farmout permitted pursuant to the
indenture, and
(G) such sale, transfer or other disposition is
not a sale, transfer or other disposition that is excluded
from the definition of "Asset Sale" because it was a sale,
lease, conveyance, disposition or other transfer of all or
substantially all of the assets of the Issuer in a
transaction which was made in compliance with the provisions
of the covenants described under "Merger, Consolidation and
Sale of Assets," provided that this clause (G) is not
applicable with respect to a release to be given in
connection with a farmout permitted pursuant to the
indenture; and
- all documentation required by the Trust Indenture Act, if any,
prior to the release of Collateral by the Trustee and, in the
event there is to be a contemporaneous substitution of property
for the Collateral subject to such sale, transfer or other
disposition, all documentation necessary to effect the
substitution of such new Collateral.
Notwithstanding the provisions described above, so long as no Event of
Default shall have occurred and be continuing, the Issuer may, without
satisfaction of the conditions described above, dispose of Hydrocarbons or other
mineral products for value in the ordinary course and engage in any number of
ordinary course activities in respect of the Collateral, in limited dollar
amounts specified by the Trust Indenture Act, upon satisfaction of certain
conditions. For example, among other things, subject to certain dollar
limitations and conditions, the Issuer would be permitted to:
- sell or otherwise dispose of any property subject to the Lien of
the indenture and the security documents, which may have become
worn out or obsolete;
- abandon, terminate, cancel, release or make alterations in or
substitutions of any leases or contracts subject to the Lien of
the indenture or any of the security documents;
- surrender or modify any franchise, license or permit subject to
the Lien of the indenture or any of the security documents which
it may own or under which it may be operating;
- alter, repair, replace, change the location or position of and
add to its structures, machinery, systems, equipment, fixtures
and appurtenances;
- demolish, dismantle, tear down or scrap any obsolete Collateral
or abandon any portion thereof; and
- grant leases or sub-leases in respect of real property to the
extent the foregoing does not constitute an Asset Sale.
DEPOSIT; USE AND RELEASE OF TRUST MONEYS
The Net Cash Proceeds associated with any Asset Sale and any Net Cash
Proceeds associated with any sale, transfer or other disposition of Collateral,
to the extent such sale, transfer or other disposition is
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not an Asset Sale by virtue of clause (F) of the definition thereof, insurance
proceeds with respect to any Collateral and condemnation (or similar) proceeds
with respect to any Collateral shall be deposited so long as any Indebtedness
under the Senior Credit Agreement or any Qualified Senior Affiliate Indebtedness
remains outstanding, with the Senior Credit Facility Representative and
otherwise into a securities account maintained by the Trustee at its corporate
trust offices or at any securities intermediary selected by the Trustee having a
combined capital and surplus of at least $250,000,000 and having a long-term
debt rating of at least "A3" by Moody's and at least "A--" by S&P styled the
"Abraxas Collateral Account" (such account being the "COLLATERAL ACCOUNT") which
shall be under the exclusive dominion and control of the Trustee. All amounts on
deposit in the Collateral Account shall be treated as financial assets and cash
funds on deposit in the Collateral Account may be invested by the Trustee, at
the direction of the Issuer, in Cash Equivalents. The Issuer will not have the
right to withdraw funds or assets from the Collateral Account except in
compliance with the terms of the indenture and all assets credited to the
Collateral Account shall be subject to a Lien in favor of the Trustee and the
holders.
Any funds deposited with the Trustee may be released to the Issuer by
its delivering to the Trustee an officer's certificate stating:
- no Event of Default has occurred and is continuing as of the date
of the proposed release;
- if:
(A) such Trust Moneys represent Collateral
Proceeds in respect of an Asset Sale, that such funds are
otherwise being applied in accordance with the covenant
"Limitation on Asset Sales" above, or
(B) such Trust Moneys represent proceeds in
respect of a casualty, expropriation or taking, such funds
will be applied to repair or replace property subject of a
casualty or condemnation or reimburse the Issuer for amounts
spent to repair or replace such property and that attached
thereto are invoices or other evidence reflecting the
amounts spent or to be spent, or
(C) such Trust Moneys represent proceeds derived
from any other manner, that such amounts are being utilized
in connection with business of the Issuer and its
Subsidiaries in compliance with the terms of the indenture;
and
- all conditions precedent in the indenture relating to the release
in question have been complied with; and
- all documentation required by the Trust Indenture Act, if any,
prior to the release of such Trust Moneys by the Trustee has been
delivered to the Trustee.
Notwithstanding the foregoing,
- if the maturity of the notes has been accelerated, and the
acceleration has not been rescinded as permitted by the
indenture, the Trustee shall apply the Trust Moneys credited to
the Collateral Account, subject to the rights of the Senior
Credit Facility Lenders under the Intercreditor Agreement, to pay
the principal of, premium, if any and accrued and unpaid interest
on the notes to the extent of such Trust Moneys;
- if the Issuer so elects, by giving written notice to the Trustee,
the Trustee shall apply Trust Moneys credited to the Collateral
Account to the payment of interest due on any interest payment
date; and
- if the Issuer so elects, by giving written notice to the Trustee,
the Trustee shall apply Trust Moneys credited to the Collateral
Account to Pay Down Debt.
LEGAL DEFEASANCE AND COVENANT DEFEASANCE
As long as the Issuer takes steps to make sure that holders will
receive all of their payments under the notes and are able to transfer the
notes, the Issuer can elect to legally release itself and any of the Subsidiary
Guarantors for any Obligations on the notes (called "LEGAL DEFEASANCE") other
than:
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- the rights of holders to receive payments from the trust
described below in respect of the principal of, premium, if any,
and interest on the notes when such payments are due;
- the Issuer's obligations with respect to the notes to issue
temporary notes, register notes, replace mutilated, destroyed,
lost or stolen notes and the maintenance of an office or agency
for payments;
- the rights, powers, trust, duties and immunities of the Trustee;
and
- the Legal Defeasance provisions of the indenture.
In addition, the Issuer may, at its option and at any time, elect to
have the obligations of the Issuer and the Subsidiary Guarantors, if any,
released with respect to certain covenants that are described in the indenture
("COVENANT DEFEASANCE"). In the event Covenant Defeasance occurs, certain events
(other than non-payment, bankruptcy, receivership, reorganization and insolvency
events and maintenance of the Guarantees) described under "Events of Default"
will no longer constitute an Event of Default with respect to the notes. The
occurrence of either Legal Defeasance or Covenant Defeasance would result in a
release of all Collateral from the Lien of the indenture and the security
documents.
In order to exercise either Legal Defeasance or Covenant Defeasance:
- the Issuer must irrevocably deposit with the Trustee, in trust,
for the benefit of the holders cash in U.S. dollars and/or
non-callable U.S. government obligations in such amounts as will
be sufficient, in the opinion of a nationally recognized firm of
independent public accountants, to pay the principal of, premium,
if any, and interest on the notes at maturity or redemption, as
the case may be:
- in the case of Legal Defeasance, the Issuer must deliver to the
Trustee an opinion of counsel in the United States reasonably
acceptable to the Trustee confirming that:
(A) the Issuer has received from, or there has
been published by, the Internal Revenue Service a ruling, or
(B) since the Issue Date, there has been a change
in the applicable federal income tax law,
in either case to the effect that the holders will not recognize
income, gain or loss for federal income tax purposes as a result
of such Legal Defeasance and will be subject to federal income
tax on the same amounts, in the same manner and at the same times
as would have been the case if such Legal Defeasance had not
occurred;
- in the case of Covenant Defeasance, the Issuer must deliver to
the Trustee an opinion of counsel in the United States reasonably
acceptable to the Trustee confirming that the holders will not
recognize income, gain or loss for federal income tax purposes as
a result of such Covenant Defeasance and will be subject to
federal income tax on the same amounts, in the same manner and at
the same times as would have been the case if such Covenant
Defeasance had not occurred;
- no Default or Event of Default shall have occurred and be
continuing on the date of such deposit or insofar as Events of
Default from bankruptcy or insolvency events are concerned, at
any time in the period ending on the 91st day after the date of
deposit;
- such Legal Defeasance or Covenant Defeasance shall not result in
a breach or violation of, or constitute a default under the
indenture or any other agreement or instrument to which the
Issuer or any of its Subsidiaries is a party or by which the
Issuer or any of its Subsidiaries is bound;
- the Issuer must deliver an officer's certificate to the Trustee
stating that the deposit was not made by the Issuer with the
intent of preferring the holders over any other creditors of the
Issuer or with the intent of defeating, hindering, delaying or
defrauding any other creditors of the Issuer or others;
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- the Issuer must deliver an officer's certificate and an opinion
of counsel to the Trustee, each stating that all conditions
precedent provided for or relating to the Legal Defeasance or the
Covenant Defeasance, as the case may be, have been complied with;
and
- the Issuer must deliver an opinion of counsel to the Trustee to
the effect that after the 91st day following the deposit, the
trust funds will not be subject to the effect of any applicable
bankruptcy, insolvency, reorganization or similar laws affecting
creditors' rights generally.
SATISFACTION AND DISCHARGE
The Issuer and the Subsidiary Guarantors will have no further
obligations under the indenture, the security documents and the Guarantees as to
all outstanding notes, other than surviving rights of registration of transfer
or exchange of the notes, when:
- either
(A) all the notes have been delivered to the
Trustee for cancellation except for (i) lost, stolen or
destroyed notes which have been replaced or paid, and (ii)
notes for whose payment money has been deposited in trust by
the Issuer or segregated and held in trust by the Issuer and
thereafter repaid to the Issuer or discharged from such
trust, or
(B) all notes not theretofore delivered to the
Trustee for cancellation have become due and payable, or are
to become due and payable within 180 days, and the Issuer
has deposited with the Trustee funds sufficient to pay and
discharge the entire Indebtedness on such notes at maturity
or redemption, as the case may be;
- the Issuer has paid all other sums payable under the indenture by
the Issuer; and
- the Issuer has delivered to the Trustee an officer's certificate
and an opinion of counsel stating that the Issuer has complied
with all conditions precedent under the indenture relating to the
satisfaction and discharge of the indenture.
MODIFICATION OF THE INDENTURE
From time to time, the Issuer, the Subsidiary Guarantors and the
Trustee, without the consent of the holders, may amend the indenture, the notes,
the Guarantees, the Intercreditor Agreement or any security document for certain
specified purposes, including curing ambiguities, defects or inconsistencies, to
comply with any requirements of the SEC in order to effect or maintain the
qualification of the indenture under the Trust Indenture Act or to make any
change that would provide any additional benefit or rights to the holders or
that does not adversely affect the rights of any holder. In formulating its
opinion on such matters, the Trustee will be entitled to rely on such evidence
as it deems appropriate, including, without limitation, solely on an opinion of
counsel.
Other modifications and amendments of the indenture, the notes, the
Guarantees, the Intercreditor Agreement or any security document may be made
with the consent of the holders of not less than a majority of the principal
amount of the then outstanding notes issued under the indenture, except that,
without the consent of each holder affected thereby, no amendment may:
- reduce the amount of notes whose holders must consent to an
amendment;
- reduce the rate of or change or have the effect of changing the
time for payment of interest, including defaulted interest, on
any notes or reduce the amount of liquidated damages payable
under the registration rights agreement;
- reduce the principal of or change or have the effect of changing
the fixed maturity of any notes, or change the date on which any
notes may be subject to redemption or repurchase, or reduce the
redemption or repurchase price therefor;
- make any notes payable in a currency other than that stated in
the notes;
- make any change in provisions of the indenture, the notes, the
Guarantees, the Intercreditor Agreement or any security document
protecting the right of each holder to receive payment of
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principal of and interest on such note on or after the due date
thereof or to bring suit to enforce such payment, or permitting
holders of a majority in principal amount of notes to waive
Defaults or Events of Default;
- amend, change or modify in any material respect the obligation of
the Issuer to make and consummate a Change of Control Offer in
the event of a Change of Control or to Pay Down Debt with respect
to any Asset Sale that has been consummated or modify any of the
provisions or definitions with respect thereto;
- modify or change any provision of the indenture, the notes, the
Guarantees, the Intercreditor Agreement, any security document or
the related definitions affecting ranking of the notes or any
Guarantee in a manner which adversely affects the holders; or
- release any Subsidiary Guarantor from any of its obligations
under its Guarantee, in any case otherwise than in accordance
with the terms of the indenture.
Also, the indenture will provide that a farmout not otherwise
qualifying as a Permitted Farmout Agreement is a Permitted Farmout Agreement if
consent to such farmout is obtained from the holders of not less than a majority
of the principal amount of the then outstanding notes issued under the
indenture.
The provisions of the Intercreditor Agreement may not be amended
without the consent of the Senior Credit Facility Representative.
GOVERNING LAW
The indenture, the notes, the Guarantees and the security documents
are governed by, and construed in accordance with, the laws of the State of New
York, except to the extent the laws of another jurisdiction may be mandatorily
applicable to certain matters under the security documents.
CONCERNING THE TRUSTEE
U.S. Bank, N.A. acts as Trustee. Its address is 180 East Fifth Street,
Saint Paul, Minnesota 55101, attn: Corporate Trust Department.
Except during the continuance of an Event of Default, the Trustee will
perform only such duties as are specifically set forth in the indenture. During
the existence of an Event of Default, the Trustee will exercise such rights and
powers vested in it by the indenture, and use the same degree of care and skill
in its exercise as a prudent man would exercise or use under the circumstances
in the conduct of his own affairs.
The indenture and the provisions of the Trust Indenture Act
incorporated by reference into the indenture contain certain limitations on the
rights of the Trustee, should it become a creditor of the Issuer or any
Subsidiary Guarantor, to obtain payments of claims in certain cases or to
realize on certain property received in respect of any such claim as security or
otherwise. Subject to the Trust Indenture Act, the Trustee is permitted to
engage in other transactions. If the Trustee acquires any conflicting interest
as described in the Trust Indenture Act after a Default has occurred and is
continuing, it must eliminate such conflict or resign.
CERTAIN DEFINITIONS
Set forth below is a summary of certain of the defined terms that are
used in the indenture. Reference is made to the indenture for the full
definition of all such terms, as well as any other terms used herein for which
no definition is provided.
"2003 CAPEX AMOUNT" equals the lesser of $15 million and the 2003
CapEx Annual Budget.
"2003 CAPEX ANNUAL BUDGET" equals the 2003 Closing CapEx Ratio
multiplied by Total Assets at December 31, 2003.
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"2003 CLOSING CAPEX RATIO" equals, for calendar year 2003, (a) $15
million or such lower amount budgeted prior to the Issue Date by the Issuer for
Capital Expenditures for such calendar period, divided by (b) Total Assets at
the end of the calendar quarter in which the Issue Date occurs.
"2004-PLUS CAPEX ANNUAL AMOUNT" equals for any annual calendar period,
the lesser of $10 million and the 2004-Plus CapEx Annual Budget.
"2004-PLUS CAPEX ANNUAL BUDGET" equals, for any annual calendar
period, 2004-Plus Closing CapEx Ratio multiplied by the Total Assets at the
start of such calendar period.
"2004-PLUS CAPEX QUARTERLY AMOUNT" equals, the lesser of $2.5 million
and one quarter of the 2004-Plus CapEx Annual Amount.
"2004-PLUS CLOSING CAPEX RATIO" equals, for any annual calendar period
starting January 1, 2004, (a) $10 million or such lower amount budgeted prior to
the Issue Date by the Issuer for Capital Expenditures for such calendar period,
divided by (b) the Total Assets at the end of the calendar quarter in which the
Issue Date occurs.
"ACQUIRED INDEBTEDNESS" means Subordinated Indebtedness of a Person or
any of its Subsidiaries the incurrence of which does not violate the terms of
the indenture:
(1) existing at the time such Person becomes a Subsidiary of the
Issuer or at the time it merges or consolidates with the Issuer or any of its
Subsidiaries, or
(2) which becomes Indebtedness of the Issuer or any of its
Subsidiaries in connection with the acquisition of assets from such Person.
Acquired Indebtedness does not include Indebtedness incurred in
connection with, or in anticipation or contemplation of, such Person becoming a
Subsidiary of the Issuer or such acquisition, merger or consolidation.
"ADJUSTED CONSOLIDATED NET TANGIBLE ASSETS" means (without
duplication), as of the date of determination the sum of:
(1) Discounted future net revenues from the proved oil and gas
reserves of the Issuer and its Subsidiaries, calculated in accordance with SEC
guidelines, but before any state or federal income tax, as estimated by a
nationally recognized firm of independent petroleum engineers as of a date no
earlier than the date of the Issuer's latest annual consolidated financial
statements.
Discounted future net revenues will be increased under clauses (a) and
(b) below and decreased under clauses (c) and (d) below, as of the date of
determination, by the estimated discounted future net revenues, calculated in
accordance with SEC guidelines but before any state of federal income taxes and
utilizing the prices utilized in the Issuer's year-end reserve report, from:
(a) estimated proved oil and gas reserves acquired since the
date of the Issuer's year-end reserve report;
(b) estimated oil and gas reserves attributable to upward
revisions of estimates of proved oil and gas reserves since the date
of the Issuer's year-end reserve report due to exploration,
development or exploitation activities,
(c) estimated proved oil and gas reserves produced or disposed
of since the date of the Issuer's year-end reserve report; and
(d) estimated oil and gas reserves attributable to downward
revisions of estimates of proved oil and gas reserves since the date
of the Issuer's year-end reserve report due to changes in geological
conditions or other factors which would, in accordance with standard
industry practice, cause such revisions.
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In the case of each of the determinations made under clauses (a)
through (d), all increases and decreases will be as estimated by the Issuer's
petroleum engineers, except that in the event that there is a Material Change as
a result of acquisitions, dispositions or revisions, then the discounted future
net revenues utilized for purposes of this clause will be confirmed by a
nationally recognized firm of independent petroleum engineers.
(2) The capitalized costs that are attributable to the oil and
gas properties of the Issuer and its Subsidiaries to which no proved oil and gas
reserves are attributable, based on the books and records of the Issuer and its
Subsidiaries as of a date no earlier than the date of the Issuer's latest annual
or quarterly financial statements.
(3) The Net Working Capital plus cash of the Issuer and its
Subsidiaries on a date no earlier than the date of the Issuer's latest
consolidated annual or quarterly financial statements.
(4) The greater of
(a) the net book value of other tangible assets of the
Issuer and its Subsidiaries on a date no earlier than the date of
the Issuer's latest consolidated annual or quarterly financial
statements, or
(b) the appraised value, as estimated by independent
appraisers, of other tangible assets of the Issuer and its
Subsidiaries as of a date no earlier than the date of the
Issuer's latest audited financial statements.
Minus the sum of
(1) Minority interests; and
(2) Any gas balancing liabilities as reflected in the Issuer's
latest audited financial statements.
Calculations of "Adjusted Consolidated Net Tangible Assets" will also
give effect, on a pro forma basis, to:
- Any Investment in another Person that becomes Subsidiary and
which is not prohibited by the indenture, to and including the
date of the transaction for which the calculation is necessary.
- The acquisition, to and including the date of the transaction, of
any business or assets, including Permitted Industry Investments.
- Any sales or other dispositions of assets permitted by the
indenture (except for sales of Hydrocarbons or other mineral
products in the ordinary course of business) occurring on or
after the date of the transaction.
"ADJUSTED ISSUE PRICE" means an amount for the most recent accrual
period equal to the initial issue price of the notes increased by the amount of
original issue discount previously includable in the gross income of a holder,
reduced by the amount of any payment previously made on the notes other than a
payment of qualified stated interest on the notes.
"AFFILIATE" of any specified Person means,
(1) any other Person who directly or indirectly through one or
more intermediaries controls, or is controlled by, or under common control with,
such specified Person; and
(2) any Related Person of such Person.
For purposes of this definition, the term "control" means the
possession, directly or indirectly, of the power to direct or cause the
direction of the management and policies of a Person, whether through the
ownership of voting securities, by contract or otherwise.
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"ASSET ACQUISITION" means:
(1) an Investment by the Issuer or any Subsidiary in any other
Person in which such Person becomes a Subsidiary, or merges with the Issuer or
any Subsidiary; or
(2) the acquisition by the Issuer or any Subsidiary of the
assets of any Person (other than a Subsidiary) which constitute all or
substantially all of the assets of such Person or comprise any division or line
of business of such Person or any other properties or assets of such Person
other than in the ordinary course of business.
"ASSET SALE" means any sale, issuance, conveyance, transfer, exchange,
lease (other than operating leases entered into in the ordinary course of
business consistent with past practices), assignment or other transfer for value
by the Issuer or any Subsidiary to any Person other than the Issuer or any
Subsidiary of:
(1) any Capital Stock of any Subsidiary; or
(2) any other property or assets of the Issuer or any Subsidiary
and any interests therein, including any disposition by a merger, consolidation
or similar transaction.
For purposes of this definition, the term "Asset Sale" does not
include:
(A) the sale, lease, conveyance, disposition or other transfer
of all or substantially all of the assets of the Issuer in a transaction which
is made in compliance with the provisions of the covenant described in "Merger,
Consolidation and Sale of Assets;"
(B) disposals or replacements of obsolete equipment in the
ordinary course of business;
(C) the sale, lease, conveyance, disposition or other transfer
of assets or property to the Issuer or one or more Wholly Owned Subsidiaries;
(D) any disposition of Hydrocarbons or other mineral products
for value in the ordinary course of business;
(E) the abandonment, surrender, termination, cancellation,
release, lease or sublease of undeveloped oil and gas properties in the ordinary
course of business or oil and gas properties which are not capable of production
in economic quantities;
or
(F) the sale, lease, conveyance, disposition or other transfer
by the Issuer or any Subsidiary of assets or property in the ordinary course of
business if the total fair market value of all the assets and property sold,
leased, conveyed, disposed or transferred since the Issue Date under this
exception does not exceed $200,000.00 in any one year.
"AVAILABLE PROCEEDS AMOUNT" means:
(1) The sum of all Collateral Proceeds and all Non-Collateral Proceeds
remaining after application to repay any Indebtedness secured by the assets that
are the subject of the Asset Sale giving rise to such Non-Collateral Proceeds.
(2) For the purpose of determining whether the Issuer must Pay Down
Debt in connection with an Asset Sale and for determining the amount of such
offer an amount equal to the amount set forth under clause (1) above minus the
total amount of all of those Asset Sale proceeds previously spent in compliance
with the terms of the section described under "Deposit; Use and Release of Trust
Moneys."
"CAPEX DEFICIT AMOUNT" equals, in any calendar quarter, the amount by
which the Capital Expenditures in any such calendar quarter (excluding the
amount of Capital Expenditures due to any Rollover Decrease because of a prior
quarter's CapEx Excess Amount) is less than the applicable CapEx Quarterly
Amount.
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"CAPEX EXCESS AMOUNT" equals, in any calendar quarter, the amount by
which Capital Expenditures in any such quarter (excluding the amount of Capital
Expenditures due to any Rollover Increase because of a prior quarter's CapEx
Deficit Amount) exceed the applicable CapEx Quarterly Amount.
"CAPEX QUARTERLY AMOUNT" means the Q1-2003 CapEx Amount, the
Q2,3,4-2003 CapEx Amount or the 2004-Plus CapEx Quarterly Amount, as applicable.
"CAPITAL EXPENDITURES" means, for any period, any direct or indirect
expenditure made in such period, in each case, whether expensed or capitalized,
in respect of the use of assets, including all Drilling Expenditures, and shall
include all investments and cash expenses and other cash outflows of the Issuer
and its Subsidiaries related to any Permitted Investments including but not
limited to those relating to joint ventures, royalty arrangements, off-balance
sheet financing, and farmout expenditures made by the Issuer or its
Subsidiaries, and expenditures made in such period in any Investment other than
Investments in cash equivalents or government backed securities, but excluding
from the definition of "Capital Expenditures" any expenditures by the Issuer or
any of its Subsidiaries to the extent the source of funds for which expenditures
was the proceeds of an equity offering by the Issuer consummated after the Issue
Date or the proceeds of any Subordinated Indebtedness incurred by the Issuer or
any of its Subsidiaries after the Issue Date in compliance with the terms of the
indenture, and further excluding from the definition of "Capital Expenditures"
any expenditures by the Issuer or any of its Subsidiaries to the extent such
expenditures constitute SG&A not prohibited by the terms of the indenture, and
further excluding from the definition of "Capital Expenditures" any expenditures
by the Issuer or any of its Subsidiaries for Qualified Lease Operating Costs.
"CAPITALIZED LEASE OBLIGATION" means the discounted present value of
the rental obligations under a lease or similar agreement that is required to be
classified and accounted for as a capital lease under GAAP.
"CAPITAL STOCK" means:
(1) with respect to a corporation, any and all shares, interests,
participations or other equivalents of corporate stock, including each class of
common stock and Preferred Stock and including any warrants, options or rights
to acquire any of the foregoing and instruments convertible into any of the
foregoing, and
(2) with respect to any Person that is not a corporation, any and all
partnership or other equity interests of such Person.
"CASH COUPON" means 11 1/2% or such higher coupon payable in cash to
the holders of the notes pursuant to the indenture.
"CASH EQUIVALENTS" means:
(1) marketable direct obligations issued by, or unconditionally
guaranteed by, the United States Government or issued by one of its agencies and
backed by the full faith and credit of the United States, in each case maturing
within one year from the date of acquisition;
(2) marketable direct obligations issued by any state of the United
States of America or any of its political subdivisions or public
instrumentalities maturing within one year from the date of acquisition and, at
the time of acquisition, having one of the two highest ratings obtainable from
either S&P or Moody's;
(3) commercial paper maturing no more than one year from its date of
creation and, at the time of acquisition, having a rating of at least A-1 from
S&P or at least P-1 from Moody's;
(4) certificates of deposit or bankers' acceptances maturing within
one year from the date of acquisition issued by any domestic bank or any United
States branch of a foreign bank having capital and surplus of at least
$250,000,000;
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(5) repurchase obligations with a term of not more than seven days for
underlying securities of the types described in clause (1) above entered into
with any bank meeting the qualifications specified in clause (4) above; and
(6) money market mutual or similar funds having assets in excess of
$100,000,000.
"CHANGE OF CONTROL" means the occurrence of any of the following:
(1) any sale, lease, exchange or other transfer (in one transaction or
a series of related transactions) of all or substantially all of the assets of
the Issuer to any Person or group of related Persons for purposes of Section
13(d) of the Exchange Act;
(2) the adoption of any plan or proposal for the liquidation or
dissolution of the Issuer;
(3) any Person or group becomes the owner, directly or indirectly,
beneficially or of record, of shares representing more than 35% of the aggregate
ordinary voting power represented by the issued and outstanding Capital Stock of
the Issuer; or
(4) the replacement of a majority of the Board of Directors of the
Issuer over a two-year period from the directors who constituted the Board of
Directors of the Issuer at the beginning of such period with directors whose
replacement was not approved by a vote of at least a majority of the Board of
Directors of the Issuer then still in office who either were members at the
beginning of such period or whose election as a member was previously so
approved.
"CLOSING SG&A RATIO" means, for any applicable calendar period, (a) $5
million or such lower amount budgeted prior to the Issue Date by the Issuer for
SG&A for such calendar period divided by (b) the Total Assets at the end of the
calendar quarter in which the Issue Date occurs.
"COLLATERAL" means, collectively, all of the property and assets
(including Trust Moneys) that are from time to time subject to, or purported to
be subject to, the Lien of the indenture or any of the security documents.
"COLLATERAL PROCEEDS" means any Net Cash Proceeds received from an
Asset Sale of Collateral.
"CONSOLIDATED EBITDA" means, for any period, the sum (without
duplication), on a consolidated basis and determined in accordance with GAAP,
of:
(1) Consolidated Net Income, and
(2) to the extent Consolidated Net Income has been reduced thereby,
(a) all income taxes paid or accrued by the Issuer or any
Subsidiary in accordance with GAAP for such period except for income
taxes attributable to extraordinary, unusual or nonrecurring gains or
losses or taxes attributable to sales or dispositions outside the
ordinary course of business,
(b) Consolidated Interest Expense,
(c) the amount of any Preferred Stock dividends paid by the
Issuer, and
(d) Consolidated Non-cash Charges, less any non-cash items
increasing Consolidated Net Income for such periods.
"CONSOLIDATED EBITDA COVERAGE RATIO" means the ratio of:
(1) Consolidated EBITDA during the four full fiscal quarters for which
financial information is available (the "Four Quarter Period") ending on or
prior to the date of the transaction giving rise to the need to calculate the
Consolidated EBITDA Coverage Ratio (the "Transaction Date") to;
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(2) Consolidated Fixed Charges for the Four Quarter Period.
For purposes of this definition, "Consolidated EBITDA" and
"Consolidated Fixed Charges" will be calculated after giving effect, without
duplication, on a pro forma basis for the calculation period to:
(1) the incurrence or repayment of
(a) Indebtedness giving rise to the need to make such
calculation, and
(b) other Indebtedness, other than the incurrence or
repayment of Indebtedness in the ordinary course of business for
working capital purposes pursuant to working capital facilities,
occurring during the Four Quarter Period or at any time subsequent to the last
day of the Four Quarter Period and on or prior to the Transaction Date, as if
such incurrence or repayment, as the case may be, occurred on the first day of
the Four Quarter Period, and
(2) any Asset Sales or Asset Acquisitions occurring during the Four
Quarter Period or at any time subsequent to the last day of the Four Quarter
Period and on or prior to the Transaction Date, as if such Asset Sale or Asset
Acquisition occurred on the first day of the Four Quarter Period. If the Issuer
or any Subsidiary guarantees Indebtedness of a third Person, the preceding
sentence will give effect to the incurrence of such guaranteed Indebtedness as
if the Issuer or such Subsidiary had directly incurred or otherwise assumed such
guaranteed Indebtedness.
In addition, in calculating "Consolidated Fixed Charges" for purposes
of determining the denominator (but not the numerator) of the Consolidated
EBITDA Coverage Ratio:
(1) interest on outstanding Indebtedness determined on a fluctuating
basis as of the Transaction Date and which will continue to be so determined
thereafter shall be deemed to have accrued at a fixed rate equal to the rate of
interest on such Indebtedness in effect on the Transaction Date;
(2) if interest on any Indebtedness actually incurred on the
Transaction Date may optionally be determined at an interest rate based upon a
factor of a prime or similar rate, a eurocurrency interbank offered rate, or
other rates, then the interest rate in effect on the Transaction Date will be
deemed to have been in effect during the Four Quarter Period;
(3) notwithstanding clauses (1) and (2) above, interest on
Indebtedness determined on a fluctuating basis, to the extent such interest is
covered by agreements relating to Interest Swap Obligations, will be deemed to
accrue at the rate per annum resulting after giving effect to the operation of
such agreements.
"CONSOLIDATED EBITDA TO CASH INTEREST EXPENSE RATIO" means, with
respect to the last day of a particular fiscal quarter of the Issuer, the ratio
of:
(1) Consolidated EBITDA during such fiscal quarter to;
(2) Consolidated Interest Expense paid in cash for such fiscal
quarter.
For purposes of this definition, "Consolidated EBITDA" and
"Consolidated Interest Expense" will be calculated after giving effect, without
duplication, on a pro forma basis for the calculation period to:
(1) the incurrence or repayment of Indebtedness, other than the
incurrence or repayment of Indebtedness in the ordinary course of business for
working capital purposes pursuant to working capital facilities, occurring
during the relevant fiscal quarter as if such incurrence or repayment, as the
case may be, occurred on the first day of the relevant fiscal quarter, and
(2) any Asset Sales or Asset Acquisitions occurring during the
relevant fiscal quarter as if such Asset Sale or Asset Acquisition occurred on
the first day of the relevant fiscal quarter. If the Issuer or any Subsidiary
guarantees Indebtedness of a third Person, the preceding sentence will give
effect to the incurrence of such guaranteed Indebtedness as if the Issuer or
such Subsidiary had directly incurred or otherwise assumed such guaranteed
Indebtedness.
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In addition, in calculating "Consolidated Interest Expense" for
purposes of determining the denominator (but not the numerator) of the
Consolidated EBITDA to Cash Interest Expense Ratio:
(1) interest on outstanding Indebtedness determined on a fluctuating
basis as of the last day of the relevant fiscal quarter of the Issuer and which
will continue to be so determined thereafter shall be deemed to have accrued at
a fixed rate equal to the rate of interest on such Indebtedness in effect on
such day;
(2) if interest on any Indebtedness actually incurred on the last day
of the relevant fiscal quarter of the Issuer may optionally be determined at an
interest rate based upon a factor of a prime or similar rate, a eurocurrency
interbank offered rate, or other rates, then the interest rate in effect on such
day will be deemed to have been in effect during the relevant fiscal quarter;
and
(3) notwithstanding clauses (1) and (2) above, interest on
Indebtedness determined on a fluctuating basis, to the extent such interest is
covered by agreements relating to Interest Swap Obligations, will be deemed to
accrue at the rate per annum resulting after giving effect to the operation of
such agreements.
"CONSOLIDATED FIXED CHARGES" means the sum, without duplication, of:
(1) Consolidated Interest Expense including any premium or penalty
paid in connection with redeeming or retiring Indebtedness prior to the stated
maturity, and
(2) the product of
(a) the amount of all dividend payments on any series of the
Issuer's Preferred Stock (other than dividends paid in Qualified
Capital Stock) paid, accrued or scheduled to be paid or accrued during
such period, times
(b) a fraction, the numerator of which is one and the denominator
of which is one minus the then current effective consolidated federal,
state and local income tax rate of such Person, expressed as a
decimal.
"CONSOLIDATED INTEREST EXPENSE" for a period means the sum, without
duplication, of:
(1) the total interest expense of the Issuer and its Subsidiaries for
such period determined on a consolidated basis in accordance with GAAP,
including
(a) any amortization of original issue discount,
(b) the net costs under Interest Swap Obligations,
(c) all capitalized interest, and
(d) the interest portion of any deferred payment obligation;
plus
(2) the interest component of Capitalized Lease Obligations paid,
accrued and/or scheduled to be paid or accrued by the Issuer and its
Subsidiaries during such period, as determined on a consolidated basis in
accordance with GAAP.
"CONSOLIDATED NET INCOME" means, with respect to the Issuer for any
period, the aggregate net income (or loss) of the Issuer and its Subsidiaries
for such period on a consolidated basis, determined in accordance with GAAP. The
following will, however, be excluded from such calculation:
(1) after-tax gains from Asset Sales or abandonments or reserves
relating thereto,
(2) after-tax items classified in accordance with GAAP as
extraordinary or nonrecurring gains,
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(3) the net income of any Person acquired in a "pooling of interests"
transaction accrued prior to the date it becomes a Subsidiary or is merged or
consolidated with the Issuer or any Subsidiary,
(4) the net income of any Subsidiary to the extent that the
declaration of dividends or similar distributions by that Subsidiary of that
income is restricted by charter, contract, operation of law or otherwise,
(5) the net income of any Person in which the Issuer or any Subsidiary
has an interest, other than a Subsidiary, except to the extent of cash dividends
or distributions actually paid to the Issuer or any Subsidiary by such Person,
(6) income or loss attributable to discontinued operations (including,
without limitation, operations disposed of during such period whether or not
such operations were classified as discontinued), and
(7) in the case of a successor to the Issuer by consolidation or
merger or as a transferee of the Issuer's assets, any net income of the
successor corporation prior to such consolidation, merger or transfer of assets.
"CONSOLIDATED NET WORTH" of any Person as of any date means
(1) the consolidated stockholders' equity of such Person, determined
on a consolidated basis in accordance with GAAP, less (without duplication)
(2) amounts attributable to Disqualified Capital Stock of such Person.
"CONSOLIDATED NON-CASH CHARGES" means, for any period, total
depreciation, depletion, amortization and other non-cash expenses reducing
Consolidated Net Income for such period, determined on a consolidated basis in
accordance with GAAP, but excluding any such charges constituting an
extraordinary item or loss or any such charge which requires an accrual of or a
reserve for cash charges for any future period.
"CONSOLIDATION" means, with respect to any Person, the consolidation
of the accounts of the Subsidiaries of such Person with those of such Person,
all in accordance with GAAP.
"CRUDE OIL AND NATURAL GAS BUSINESS" means:
(1) the acquisition, exploration, development, operation and
disposition of interests in oil, gas and other hydrocarbon properties located in
North America, and
(2) the gathering, marketing, treating, processing, storage, selling
and transporting of any production from such interests or properties of the
Issuer or those of others.
"CRUDE OIL AND NATURAL GAS HEDGE AGREEMENTS" means any oil and gas
agreements and other agreements or arrangements entered into by a Person in the
ordinary course of business and that is designed to provide protection against
oil and natural gas price fluctuations.
"CRUDE OIL AND NATURAL GAS PROPERTIES" means all Properties, including
equity or other ownership interests in those Properties, owned by any Person
which have been assigned "proved oil and gas reserves" as defined in Rule 4-10
of Regulation S-X of the Securities Act as in effect on the Issue Date.
"CRUDE OIL AND NATURAL GAS RELATED ASSETS" means any Investment or
capital expenditure (but not including additions to working capital or
repayments of any revolving credit or working capital borrowings) by the Issuer
or any Subsidiary which is related to the business of the Issuer and its
Subsidiaries as it is conducted on the date of the Asset Sale giving rise to the
Net Cash Proceeds to be reinvested.
"CURRENCY AGREEMENT" means any foreign exchange contract, currency
swap agreement or other similar agreement or arrangement designed to protect
against fluctuations in currency values.
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"DEFAULT" means an event or condition that is, or with the lapse of
time or the giving of notice or both would be, an Event of Default.
"DISQUALIFIED CAPITAL STOCK" means any Capital Stock which, by its
terms (or by the terms of any security into which it is convertible or for which
it is exchangeable), or upon the happening of any event, matures or is
mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or
is mandatorily redeemable at the sole option of the holder thereof, in whole or
in part, in either case, on or prior to the final maturity of the notes.
"DRILLING EXPENDITURES" means any direct or indirect expenditure, in
each case, whether expensed or capitalized, in respect of drilling.
"EASTSIDE COAL" means Eastside Coal Company, Inc., a Colorado
corporation.
"EXCESS CASH FLOW" means, for any period, Consolidated EBITDA of the
Issuer and its Subsidiaries for such period, minus any increase in the Net
Working Capital of the Issuer and its Subsidiaries from the beginning of such
period to the end of a such period or plus any decrease in the Net Working
Capital of the Issuer and its Subsidiaries from the beginning of such period to
the end of a such period (as the case may be), minus Capital Expenditures made
by the Issuer and its Subsidiaries during that period to the extent such Capital
Expenditures did not reduce Consolidated EBITDA, minus any cash interest paid by
the Issuer and its Subsidiaries during that period, minus any cash taxes paid by
the Issuer and its Subsidiaries during that period, minus any amount applied by
the Issuer and its Subsidiaries to Pay Down Debt during that period, minus (to
the extent included in Consolidated EBITDA) any proceeds received during that
period from any equity offering by the Issuer or from any Subordinated
Indebtedness of the Issuer or any of its Subsidiaries.
"EQUITY OFFERING" means an offering of the Issuer's Qualified Capital
Stock.
"FAIR MARKET VALUE" means, with respect to any asset or property, the
price which could be negotiated in an arm's-length, free market transaction, for
cash, between an informed and willing seller and an informed and willing buyer,
neither of whom is under undue pressure or compulsion to complete the
transaction. Fair market value shall be determined by the Board of Directors of
the Issuer acting reasonably and in good faith; PROVIDED, HOWEVER, that if the
aggregate non-cash consideration to be received by the Issuer or any Subsidiary
from any Asset Sale shall reasonably be expected to exceed $5,000,000, then fair
market value shall be determined by an Independent Advisor.
"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board as of any date of determination.
"HYDROCARBONS" means oil, gas, casing head gas, drip gasoline, natural
gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and
all constituents, elements or compounds thereof and products processed
therefrom.
"INDEBTEDNESS" means with respect to any Person, without duplication:
(1) all Obligations for borrowed money,
(2) all Obligations evidenced by bonds, debentures, notes or other
similar instruments,
(3) all Capitalized Lease Obligations,
(4) all Obligations for the deferred purchase price of property, all
conditional sale obligations and all Obligations under any title retention
agreement but excluding trade accounts payable,
(5) all Obligations for the reimbursement of any obligor on a letter
of credit, banker's acceptance or similar credit transaction,
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(6) guarantees and other contingent obligations in respect of
Indebtedness referred to in clauses (1) through (5) above and clause (8) below,
(7) all Obligations of any other Person of the type referred to in
clauses (1) through (6) above which are secured by any Lien on any property or
asset of such Person, the amount of such Obligation being deemed to be the
lesser of the fair market value of such property or asset or the amount of the
Obligation so secured,
(8) all Obligations under Currency Agreements and Interest Swap
Obligations,
(9) all Disqualified Capital Stock issued by such Person with the
amount of Indebtedness represented by such Disqualified Capital Stock being
equal to the greater of its voluntary or involuntary liquidation preference and
its maximum fixed redemption price or repurchase price; and
(10) all Obligations in respect of production payments and forward
sales.
For purposes of this definition:
(1) the "maximum fixed repurchase price" of any Disqualified Capital
Stock which does not have a fixed repurchase price shall be calculated in
accordance with the terms of such Disqualified Capital Stock as if it were
purchased on any date on which Indebtedness shall be required to be determined
pursuant to the indenture, and if such price is based upon, or measured by, the
fair market value of the Disqualified Capital Stock, the fair market value shall
be determined reasonably and in good faith by the Board of Directors of the
Issuer.
(2) The "amount" or "principal amount" of Indebtedness at any time
will be:
(a) for any Indebtedness issued at a price that is less than
its principal amount at maturity, the face amount of the liability,
(b) for any Capitalized Lease Obligation, the amount
determined in accordance with its definition above,
(c) for any Interest Swap Obligations included in the
definition of Permitted Indebtedness, zero,
(d) for all other unconditional obligations, the amount
determined in accordance with GAAP, and
(e) for all other contingent obligations, the maximum
liability at such date of such Person.
"INDEPENDENT ADVISOR" means a reputable accounting, appraisal or
nationally recognized investment banking, engineering or consulting firm which:
(1) does not, and whose directors, officers and employees or
Affiliates do not, have a direct or indirect material financial interest in the
Issuer, and
(2) in the judgment of the Board of Directors of the Issuer, is
otherwise disinterested, independent and qualified to perform the task for which
it is to be engaged.
"INTERCREDITOR AGREEMENT" means the Intercreditor Agreement to be
dated on or about the Issue Date entered into by the Senior Credit Facility
Representative and the Trustee and also acknowledged by the Issuer and certain
Subsidiaries of the Issuer, or any successor or replacement agreement, as such
agreement has been or may be amended (including any amendment and restatement
thereof), supplemented, replaced, restated or otherwise modified from time to
time.
"INTEREST SWAP OBLIGATION" means obligations under interest rate
swaps, caps, floors, collars and similar agreements, whereby, directly or
indirectly, a Person is entitled to receive payments calculated by applying
either a floating or a fixed rate of interest on a stated notional amount in
exchange for payments
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made by another Person calculated by applying a fixed or a floating rate of
interest on the same notional amount.
"INVESTMENT" by a Person means any direct or indirect:
(1) loan, advance or other extension of credit (including a guarantee)
or capital contribution to others,
(2) purchase or acquisition of any Capital Stock, bonds, notes,
debentures or other securities or evidences of Indebtedness issued by another
Person ,
(3) guarantee or assumption of the Indebtedness of another Person
(other than the guarantee or assumption of Indebtedness of the Person or a
Subsidiary of the Person which is made in compliance with the provisions of
"Certain Covenants -- Limitation on Incurrence of Additional Indebtedness"
above), and
(4) other items that would be classified as investments on a balance
sheet of such Person prepared in accordance with GAAP.
Notwithstanding the foregoing, "Investment" excludes extensions of
trade credit on commercially reasonable terms in accordance with the normal
trade practices of the Issuer and its Subsidiaries. The amount of any Investment
will not be adjusted for increases or decreases in value, or write-ups,
write-downs or write-offs with respect to that Investment. If the Issuer or its
Subsidiaries sell or otherwise dispose of any Capital Stock of any Subsidiary
such that, after giving effect to any such sale or disposition, it ceases to be
a Subsidiary of the Issuer, the Issuer will be deemed to have made an Investment
on the date of any such sale or disposition equal to the fair market value of
the Capital Stock of such Subsidiary not sold or disposed of.
"ISSUE DATE" means the date of original issuance of the notes.
"ISSUER" means Abraxas Petroleum Corporation, a Nevada corporation.
"ISSUER PROPERTIES" means all Properties, and equity, partnership or
other ownership interests therein, that are related or incidental to, or used or
useful in connection with, the conduct or operation of any business activities
of the Issuer or any of its Subsidiaries, which business activities are not
prohibited by the terms of the indenture.
"LIEN" means any lien, mortgage, deed of trust, pledge, security
interest, floating or other charge or encumbrance of any kind (including any
conditional sale or other title retention agreement, any lease in the nature
thereof and any agreement to give any security interest).
"MATERIAL CHANGE" means an increase or decrease of more than 10%
during a fiscal quarter in the discounted future net cash flows (excluding
changes that result solely from changes in prices) from proved oil and gas
reserves of the Issuer and its Subsidiaries (before any state or federal income
tax); PROVIDED, HOWEVER, that the following will be excluded from the
calculation of Material Change:
(1) any acquisitions during the quarter of oil and gas reserves that
have been estimated by independent petroleum engineers and on which a report or
reports exist,
(2) any disposition of properties existing at the beginning of such
quarter that have been disposed of as provided in "Limitation on Asset Sales,"
and
(3) any reserves added during the quarter attributable to the drilling
or recompletion of wells not included in previous reserve estimates, but which
will be included in future quarters.
"MORTGAGE" means a mortgage or deed of trust dated as of the Issue
Date granted by the Issuer or any Subsidiary for the benefit of the Trustee and
the holders, as the same may be amended, supplemented or modified from time to
time in accordance with the terms thereof and of the indenture.
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"NET CASH PROCEEDS" means the proceeds in the form of cash or Cash
Equivalents including payments in respect of deferred payment obligations when
received in the form of cash or Cash Equivalents received by the Issuer or any
Subsidiary from any Asset Sale, sale, transfer or other disposition net of:
(1) reasonable out-of-pocket expenses and fees relating to such Asset
Sale, sale, transfer or other disposition (including, without limitation, legal,
accounting and investment banking fees and sales commissions),
(2) taxes paid or payable after taking into account any reduction in
consolidated tax liability due to available tax credits or deductions and any
tax sharing arrangements,
(3) appropriate amounts (determined by the Chief Financial Officer of
the Issuer) to be provided by the Issuer or any Subsidiary, as the case may be,
as a reserve, in accordance with GAAP, against any post closing adjustments or
liabilities associated with such Asset Sale, sale, transfer or other disposition
and retained by the Issuer or any Subsidiary, as the case may be, after such
Asset Sale, sale, transfer or other disposition, including pension and other
post-employment benefit liabilities, liabilities related to environmental
matters and liabilities under any indemnification obligations associated with
such Asset Sale, sale, transfer or other disposition (but excluding any payments
which, by the terms of the indemnities will not, be made during the term of the
notes), and
(4) the aggregate amount of cash and Cash Equivalents so received
which is used to retire any then existing Indebtedness (other than Indebtedness
under the Senior Credit Agreement, Qualified Senior Affiliate Indebtedness or
the notes) which is secured by a Lien on the property subject of the Asset Sale,
sale, transfer or other disposition.
"NET WORKING CAPITAL" means:
(1) all current assets of the Issuer and its Subsidiaries, MINUS
(2) all current liabilities of the Issuer and its Subsidiaries, except
current liabilities included in Indebtedness, MINUS
(3) all cash of the Issuer and its Subsidiaries,
in each case as set forth in the Issuer's financial statements
prepared in accordance with GAAP.
"OBLIGATIONS" means any principal, premium, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"OIL AND GAS ASSETS" means the Crude Oil and Natural Gas Properties
and natural gas processing facilities of the Issuer and/or any of its
Subsidiaries.
"PAY DOWN DEBT" means:
- first, making a payment under the Senior Credit Agreement with a
permanent reduction of the indebtedness outstanding under the
Senior Credit Agreement to the extent making a payment on the
Senior Credit Agreement with a permanent reduction of the
indebtedness outstanding under the Senior Credit Agreement is
required under the terms of the Senior Credit Agreement and/or
the Intercreditor Agreement,
- second, making a payment of principal and/or accrued interest on,
or redeeming, exchanging, discharging, defeasing, or purchasing
and retiring, notes in whole or in part, to the extent permitted
by the Senior Credit Agreement and the Intercreditor Agreement,
- third, (i) first, making scheduled or mandatory paydowns on
Indebtedness under the Senior Credit Agreement and paying down
any term loans under the Senior Credit Agreement to the extent
permitted by the Senior Credit Agreement, whether or not then due
and payable ("Term Loan Paydowns"), and if all Term Loan Paydowns
are made (the "Term Loan Amounts") so that such outstanding
amounts under the Senior Credit Agreement have been paid down
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completely, then (ii) second, any amount remaining after payment
of the Term Loan Amounts will be applied to outstanding amounts
under any revolving credit tranche under the Senior Credit
Agreement for permanent reduction of the commitment under the
revolving credit tranche, and if no amounts are outstanding under
any such revolving credit tranche, then at that time the Issuer
will terminate that credit facility, and
- fourth, making a payment of principal and/or accrued interest on,
or redeeming, exchanging, discharging, defeasing, or purchasing
and retiring, notes in whole or in part.
"PERMITTED INDEBTEDNESS" means, without duplication, each of the
following:
(1) Indebtedness under the notes, the indenture, the Guarantees and
the security documents;
(2) Obligations under Interest Swap Obligations covering Indebtedness
if these Interest Swap Obligations are entered into to protect against
fluctuations in interest rates on Indebtedness incurred in accordance with the
indenture to the extent the notional principal amount of such Interest Swap
Obligations is not greater than the principal amount of the Indebtedness to
which such Interest Swap Obligation relates;
(3) Indebtedness of a Subsidiary to the Issuer or to a Wholly Owned
Subsidiary for so long as such Indebtedness is held by the Issuer or a Wholly
Owned Subsidiary, in each case subject to no Lien held by a Person other than
the Issuer or a Wholly Owned Subsidiary; PROVIDED, HOWEVER, that if as of any
date any Person other than the Issuer or a Wholly Owned Subsidiary owns or holds
any such Indebtedness or holds a Lien in respect of such Indebtedness, such date
shall be deemed the incurrence of Indebtedness not constituting Permitted
Indebtedness by the issuer of such Indebtedness;
(4) Indebtedness of the Issuer to a Wholly Owned Subsidiary for so
long as such Indebtedness is held by a Wholly Owned Subsidiary, in each case
subject to no Lien; PROVIDED, HOWEVER, that
(a) any Indebtedness of the Issuer to any Wholly Owned
Subsidiary that is not a Subsidiary Guarantor is unsecured and
subordinated, pursuant to a written agreement, to the Issuer's
Obligations under the indenture and the notes, and
(b) if as of any date any Person other than a Wholly Owned
Subsidiary owns or holds any such Indebtedness or holds a Lien in
respect of such Indebtedness, such date shall be deemed the incurrence
of Indebtedness not constituting Permitted Indebtedness by the Issuer;
(5) Indebtedness arising from a bank or other financial institution
inadvertently honoring a check, draft or similar instrument (except in the case
of daylight overdrafts) drawn against insufficient funds in the ordinary course
of business; PROVIDED, HOWEVER, that such Indebtedness is extinguished within
two Business Days of incurrence;
(6) Indebtedness of the Issuer or any of its Subsidiaries represented
by letters of credit for the account of the Issuer or any such Subsidiary, as
the case may be, in order to provide security for workers' compensation claims,
payment obligations in connection with self-insurance or similar requirements in
the ordinary course of business;
(7) Capitalized Lease Obligations and Purchase Money Indebtedness not
exceeding $2,000,000 at any one time outstanding;
(8) Permitted Operating Obligations in an aggregate amount at any time
outstanding not to exceed $750,000;
(9) Obligations arising in connection with Crude Oil and Natural Gas
Hedge Agreements with financial institutions (excluding forward sales and
production payments);
(10) Indebtedness under Currency Agreements with financial
institutions; PROVIDED, HOWEVER, that in the case of Currency Agreements which
relate to Indebtedness, such Currency Agreements do not increase Indebtedness of
the Issuer and its Subsidiaries outstanding other than as a result of
fluctuations in foreign currency exchange rates or by reason of fees,
indemnities and compensation payable thereunder;
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(11) Additional Indebtedness in an aggregate principal amount at any
time outstanding not to exceed $500,000;
(12) Indebtedness outstanding on the Issue Date except to the extent
the Indebtedness thereunder was taken up by the notes;
(13) Indebtedness under the Senior Credit Agreement (including (i) any
fees and expenses incurred by the Issuer or any of its Subsidiaries incurred in
connection with the Senior Credit Agreement (including, but not limited to,
those owed to any Person not affiliated to the Issuer or any of its
Subsidiaries) in connection with any amendment (including any amendment and
restatement thereof), supplement, replacement, restatement or other modification
from time to time, including any agreements (and related instruments and
documents) extending the maturity of, refinancing, replacement or other
restructuring of all or any portion of the Indebtedness under such Senior Credit
Agreement (and related instruments and documents) or any successor or
replacement agreements (and related instruments and documents) and (ii) any
capitalized interest, fees, or other expenses incurred by the Issuer or any of
its Subsidiaries whether or not charged to a loan account or any similar account
created under the Senior Credit Agreement (clauses (i) and (ii), the "Related
Indebtedness")); provided, that the principal amount of the Indebtedness under
the Senior Credit Agreement (excluding the Related Indebtedness and excluding
any Qualified Senior Affiliate Indebtedness) shall not at any time exceed the
sum of (a) $50 million less the aggregate amount applied from time to time by
the Issuer or any of its Subsidiaries to repay the Senior Credit Agreement
Indebtedness which is accompanied by a corresponding permanent reduction of the
Revolver Commitment under the Senior Credit Agreement plus (b) (x) $15 million,
if the then applicable Revolver Commitment under the Senior Credit Agreement is
$25 million or greater, (y) $10 million, if the then applicable Revolver
Commitment under the Senior Credit Agreement is less than $25 million and
greater than or equal to $15 million or (z) $5 million, if the then applicable
Revolver Commitment under the Senior Credit Agreement is less than $15 million
("Indebtedness under the Senior Credit Agreement"); provided further that, the
aggregate amount that has been applied by the Issuer or any of its Subsidiaries
to repay the Indebtedness under the Senior Credit Agreement which was
accompanied by a corresponding permanent commitment reduction can be established
by the Issuer at any time by providing the Trustee with an officer's certificate
of the Issuer stating such amount;
(14) Qualified Senior Affiliate Indebtedness; and
(15) Permitted Subordinated Indebtedness.
"PERMITTED INDUSTRY INVESTMENTS" means:
(1) capital expenditures, including acquisitions of Issuer Properties
and interests therein;
(2) (a) operating agreements, joint ventures, working interests,
royalty interests, mineral leases, unitization agreements, pooling arrangements
or other similar or customary agreements, transactions, properties, interests or
arrangements, and Investments and expenditures in connection with such
agreements, interests or arrangements, in each case made or entered into in the
ordinary course of the oil and gas business,
and
(b) exchanges of Issuer Properties for other Issuer Properties of
at least equivalent value as determined in good faith by the
Board of Directors of the Issuer; and
(3) Investments of operating funds on behalf of co-owners of Crude Oil
and Natural Gas Properties pursuant to joint operating agreements.
"PERMITTED INVESTMENTS" means:
(1) Investments by the Issuer or any Subsidiary in any Person that (i)
is or will become immediately after such Investment a Subsidiary or that will
merge or consolidate into the Issuer or a Subsidiary, and (ii) is not subject to
any Payment Restriction;
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(2) Investments in the Issuer by any Subsidiary; PROVIDED, HOWEVER,
that any Indebtedness evidencing any such Investment held by a Subsidiary that
is not a Subsidiary Guarantor is unsecured and subordinated, pursuant to a
written agreement, to the Issuer's Obligations under the notes and the
indenture;
(3) Investments in cash and Cash Equivalents;
(4) Investments made by the Issuer or its Subsidiaries as a result of
consideration received in connection with an Asset Sale made in compliance with
"Certain Covenants -- Limitation on Asset Sales" above;
(5) Permitted Industry Investments; and
(6) Investments in any Person so long as such Investments are made on
an arm's-length basis.
"PERMITTED LIENS" means:
(1) Liens arising under the indenture or the security documents;
(2) Liens securing the notes;
(3) Liens arising under the Senior Credit Agreement or the guarantees
and security documents entered into in connection with the Senior Credit
Agreement, and Liens securing Qualified Senior Affiliate Indebtedness;
(4) Liens securing the Guarantees;
(5) Liens for taxes, assessments or governmental charges or claims
that are either
(a) not delinquent or
(b) contested in good faith by appropriate proceedings and
as to which the Issuer has set aside on its books such reserves as may
be required pursuant to GAAP;
(6) statutory and contractual Liens of landlords to secure rent
arising in the ordinary course of business to the extent such Liens relate only
to the tangible property of the lessee which is located on such property and
Liens of carriers, warehousemen, mechanics, builders, suppliers, materialmen,
repairmen and other Liens imposed by law incurred in the ordinary course of
business for sums not yet delinquent or being contested in good faith, if such
reserve or other appropriate provision, if any, as shall be required by GAAP
shall have been made in respect thereof;
(7) Liens incurred on deposits made in the ordinary course of
business:
(a) in connection with workers' compensation, unemployment
insurance and other types of social security, including any Lien
securing letters of credit issued in the ordinary course of business
consistent with past practice in connection therewith, or
(b) to secure the performance of tenders, statutory
obligations, surety and appeal bonds, bids, leases, government
contracts, performance and return-of-money bonds and other similar
obligations (exclusive of obligations for the payment of borrowed
money);
(8) easements, rights-of-way, zoning restrictions, restrictive
covenants, minor imperfections in title and other similar charges or
encumbrances in respect of real property not interfering in any material respect
with the ordinary conduct of the business of the Issuer and its Subsidiaries;
(9) any interest or title of a lessor under any Capitalized Lease
Obligation not prohibited by the terms of the indenture; provided that such
Liens do not extend to any Property which is not leased Property subject to such
Capitalized Lease Obligation;
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(10) Liens securing reimbursement obligations, not to exceed $100,000
in the aggregate at any time outstanding, with respect to commercial letters of
credit which encumber documents and other property relating to such letters of
credit and products and proceeds thereof;
(11) Liens encumbering deposits made to secure obligations arising
from statutory, regulatory, contractual, or warranty requirements, including
rights of offset and set-off;
(12) Liens securing Interest Swap Obligations which Interest Swap
Obligations relate to Indebtedness that is otherwise permitted under the
indenture and Liens securing Crude Oil and Natural Gas Hedge Agreements;
(13) statutory Liens on pipeline or pipeline facilities, Hydrocarbons
or Properties which arise out of operation of law;
(14) royalties, overriding royalties, net profit interests,
reversionary interests, operating agreements and other similar interests,
properties, arrangements and agreements, all as ordinarily exist with respect to
Properties of the Issuer and its Subsidiaries or otherwise as are customary in
the oil and gas business, and all as relate to mineral leases and mineral
interests of the Issuer and its Subsidiaries;
(15) any
(a) interest or title of a lessor or sublessor under any
lease,
(b) restriction or encumbrance that the interest or title of
such lessor or sublessor may be subject to (including, without
limitation, ground leases or other prior leases of the demised
premises, mortgages, mechanics' liens, builders' liens, tax liens, and
easements), or
(c) subordination of the interest of the lessee or sublessee
under such lease to any restrictions or encumbrance referred to in the
preceding clause (b);
(16) Liens in favor of collecting or payor banks having a right of
setoff, revocation, refund or chargeback with respect to money or instruments on
deposit with or in possession of such bank;
(17) judgment and attachment Liens not giving rise to an Event of
Default;
(18) Liens securing Acquired Indebtedness incurred in accordance with
"Certain Covenants -- Limitation on Incurrence of Additional Indebtedness"
above; PROVIDED, HOWEVER, that
(19) such Liens secured such Acquired Indebtedness at the time of and
prior to the incurrence of such Acquired Indebtedness by the Issuer or a
Subsidiary and were not granted in connection with, or in anticipation of, the
incurrence of such Acquired Indebtedness by the Issuer or a Subsidiary, and
(20) such Liens do not extend to or cover any property or assets of
the Issuer or of any of its Subsidiaries other than the property or assets that
secured the Acquired Indebtedness (and the proceeds of such property and assets)
prior to the time such Indebtedness became Acquired Indebtedness of the Issuer
or a Subsidiary and are no more favorable to the lienholders than those securing
the Acquired Indebtedness prior to the incurrence of such Acquired Indebtedness
by the Issuer or a Subsidiary.
(21) Liens existing on the Issue Date;
(22) Liens securing Refinancing Indebtedness which is incurred to
Refinance any Indebtedness permitted under the indenture and which has been
secured by a Lien permitted under the indenture and which has been incurred in
accordance with the provisions of the indenture; PROVIDED, HOWEVER, that such
Liens
(a) are no less favorable to the holders and are not more
favorable to the lienholders with respect to such Liens than the Liens
in respect of the Indebtedness being Refinanced and
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(b) do not extend to or cover any Property of the Issuer or
any of its Subsidiaries that would not have secured the Indebtedness
so Refinanced under the terms of the documents governing the Liens
securing the Indebtedness being Refinanced;
(21) Liens securing Indebtedness of the Issuer or any Subsidiary in an
aggregate principal amount at any time outstanding not to exceed the sum of
$500,000.00; and
(22) Permitted Farmout Agreements.
"PERMITTED OPERATING OBLIGATIONS" means Indebtedness of the Issuer or
any Subsidiary in respect of one or more standby letters of credit, bid,
performance or surety bonds, or other reimbursement obligations, issued for the
account of, or entered into by, the Issuer or any Subsidiary in the ordinary
course of business consistent with past practices (excluding obligations related
to the purchase by the Issuer or any Subsidiary of Hydrocarbons for which the
Issuer or any Subsidiary has contracts to sell), or in lieu of any thereof or in
addition to any thereto, guarantees and letters of credit supporting any such
obligations and Indebtedness (in each case, other than for an obligation for
borrowed money, other than borrowed money represented by any such letter of
credit, bid, performance or surety bond, or reimbursement obligation itself, or
any guarantee and letter of credit related thereto).
"PERSON" means an individual, partnership, corporation, unincorporated
organization, limited liability company, trust, estate, or joint venture, or a
governmental agency or political subdivision thereof.
"PREFERRED STOCK" of any Person means any Capital Stock of such Person
that has preferential rights to any other Capital Stock of such Person with
respect to dividends or redemptions or upon liquidation.
"PROPERTY" OR "PROPERTY" means, with respect to any Person, any
interests of such Person in any kind of property or asset, whether real,
personal or mixed, or tangible or intangible, including, without limitation,
Capital Stock, partnership interests and other equity or ownership interests in
any other Person.
"PURCHASE MONEY INDEBTEDNESS" means Indebtedness the net proceeds of
which are used to finance the cost (including the cost of construction) of
property or assets acquired in the normal course of business by the Person
incurring such Indebtedness.
"Q1-2003 BUDGET" equals the Q1-2003 Closing Budget Ratio multiplied by
the Total Assets at March 31, 2003.
"Q1-2003 CAPEX AMOUNT" equals the lesser of $8 million and the Q1-2003
Budget.
"Q1-2003 CLOSING BUDGET RATIO" equals (a) $8 million or such lower
amount budgeted prior to the Issue Date by the Issuer for Capital Expenditures
for the first calendar quarter of 2003 divided by (b) Total Assets at the end of
the calendar quarter in which the Issue Date occurs.
"Q2,3,4-2003 BUDGET" equals, for each of the last three calendar
quarters of 2003, the applicable Q2,3,4-2003 Closing Budget Ratio multiplied by
the Total Assets at the start of the applicable calendar quarter in 2003.
"Q2,3,4-2003 CAPEX AMOUNT" equals, for each of the last three calendar
quarters of 2003, the lesser of $2.5 million and the Q2,3,4-2003 Budget.
"Q2,3,4-2003 CLOSING BUDGET RATIO" equals, for each of the last three
calendar quarters of 2003, (a) $2.5 million or such lower amount budgeted prior
to the Issue Date by the Issuer for Capital Expenditures for such calendar
quarter divided by (b) Total Assets at the end of the calendar quarter in which
the Issue Date occurs.
"QUALIFIED CAPITAL STOCK" means any Capital Stock that is not
Disqualified Capital Stock.
"QUALIFIED SENIOR AFFILIATE INDEBTEDNESS" means Indebtedness of the
Issuer to the Senior Credit Facility Representative, any Senior Credit Facility
Lender or any Affiliate of the Senior Credit Facility
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Representative or any such lender in connection with (x) hedging activities
(i.e., Indebtedness under Hedge Agreements) or (y) cash management services
entered into in the ordinary course of business with any such Person (i.e.,
Indebtedness under Bank Products Agreements).
"QUALIFIED LEASE OPERATING COSTS" means lease operating costs
reasonably incurred in the ordinary course of business consistent with past
practices and industry standards pursuant to a budget approved by the Board of
Directors of the Issuer and relating to proved developed oil and gas properties.
"REFINANCE" means, in respect of any security or Indebtedness, to
refinance, extend, renew, refund, repay, prepay, redeem, defease or retire, or
to issue a security or Indebtedness in exchange or replacement for, such
security or Indebtedness in whole or in part.
"REFINANCING INDEBTEDNESS" means any Indebtedness that is the result
of Refinancing by the Issuer or any Subsidiary of Indebtedness incurred in
accordance with the covenant described in "Limitation on Incurrence of
Additional Indebtedness" above (other than pursuant to clause (1) (2), (3), (4),
(5), (6), (7), (8), (9), (10), (11), (12), or (15) of the definition of
Permitted Indebtedness), in each case that does not:
(1) result in an increase in the total principal amount of
Indebtedness of the Issuer or such Subsidiary as of the date of such proposed
Refinancing (other than increases from any premium required to be paid under the
terms of the instrument governing such Indebtedness, capitalized interest, and
the amount of reasonable expenses incurred by the Issuer or such Subsidiary in
connection with such Refinancing, all of which are included in the term
"Refinancing Indebtedness"), or
(2) create Indebtedness with
(a) a Weighted Average Life to Maturity that is less than
the Weighted Average Life to Maturity of the Indebtedness being
Refinanced or
(b) a final maturity earlier than the final maturity of the
Indebtedness being Refinanced;
PROVIDED, HOWEVER, that
(i) if such Indebtedness being Refinanced is Indebtedness solely of the Issuer
or a Subsidiary Guarantor or is Indebtedness of the Issuer and any Subsidiary
Guarantor or Subsidiary Guarantors, then such Refinancing Indebtedness shall be
Indebtedness solely of the Issuer or such Subsidiary Guarantor or of the Issuer
and such Subsidiary Guarantor or Subsidiary Guarantors, as the case may be, and
(ii) if such Indebtedness being Refinanced is subordinate or junior to the notes
or a Guarantee, then such Refinancing Indebtedness shall be subordinate to the
notes or such Guarantee, as the case may be, at least to the same extent and in
the same manner as the Indebtedness being Refinanced.
"RELATED PERSON" of any Person means any other Person directly or
indirectly owning 10% or more of the outstanding voting common stock of such
Person (or, in the case of a Person that is not a corporation, 10% or more of
the equity interest in such Person).
"RESTRICTED CASH" means, at any time, the lesser of (i) $5 million and
(ii) the minimum amount of cash required to be maintained at that time by the
Issuer pursuant to the terms of the Senior Credit Agreement.
"ROLLOVER DECREASE" means, for a particular calendar quarter, the
amount of reduced availability of SG&A or Capital Expenditures, as the case may
be, due to any a prior quarter's SG&A Excess Amount or CapEx Excess Amount.
"ROLLOVER INCREASE" means, for a particular calendar quarter, the
amount of increased availability of SG&A or Capital Expenditures, as the case
may be, due to any a prior quarter's SG&A Deficit Amount or CapEx Deficit
Amount.
"SANDIA" means Sandia Oil and Gas Company, a Texas corporation.
"SANDIA OPERATING" means Sandia Operating Corp., a Texas corporation,
and Wholly-Owned Subsidiary of Sandia.
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"SALE AND LEASEBACK TRANSACTION" means any direct or indirect
arrangement with any Person or to which any such Person is a party, providing
for the leasing to the Issuer or any Subsidiary of any property, whether owned
by the Issuer or such Subsidiary at the Issue Date or later acquired which has
been or is to be sold or transferred by the Issuer or any Subsidiary to such
Person or to any other Person from whom funds have been or are to be advanced by
such Person on the security of such property.
"SECURITY DOCUMENTS" means, collectively, the Mortgages and all
security agreements, mortgages, deeds of trust, collateral assignments or other
instruments evidencing or creating any security interests in favor of the
Trustee in all or any portion of the Collateral, in each case as amended,
supplemented or modified from time to time in accordance with their terms and
the terms of the indenture.
"SENIOR CREDIT AGREEMENT" means the Loan and Security Agreement, dated
as of January 22, 2003, entered into by the Issuer and certain Subsidiaries of
the Issuer, and the lenders named therein, or any successor or replacement
agreements, whether with the same or any other lender, group of lenders,
trustee, agent, note holder or group of note holders, together with the related
documents thereto (including, without limitation, any promissory notes,
guarantee agreements, security documents), in each case as such agreements,
instruments and documents have been or may be amended (including any amendment
and restatement thereof), supplemented, replaced, restated or otherwise modified
from time to time, including any agreements (and related instruments and
documents) extending the maturity of, refinancing, replacing or otherwise
restructuring all or any portion of the Indebtedness under such agreements (and
related instruments and documents) or any successor or replacement agreements
(and related instruments and documents).
"SENIOR CREDIT FACILITY LENDERS" means any holders of any Indebtedness
under the Senior Credit Agreement.
"SENIOR CREDIT FACILITY REPRESENTATIVE" means the Person designated in
the Intercreditor Agreement as the Senior Credit Facility Representative with
respect to the Senior Credit Agreement.
"SG&A" means, for any period, amounts expended by the Issuer and its
Subsidiaries on selling, general and administrative expenses (as determined in
accordance with GAAP consistent with past practices), but excluding (without
duplication with respect to such exclusions):
- costs and expenses of the Issuer incurred in connection with
(i) issuing the notes and shares of common stock
contemporaneously issued by the Issuer, (ii) obtaining the
loan evidenced by the Senior Credit Agreement, and (iii) the
sale of stock described under the discussion above entitled
"Business--Recent Developments--Financial
Restructuring--Sale of Stock of Canadian Abraxas and Old
Grey Wolf,"
- legal and accounting fees not to exceed $40,000 in any
calendar year incurred by the Issuer in connection with
preparing and filing the reports, information and documents
required to be delivered to the Trustee as described above
in the discussion entitled "Reports to Holders,"
- bonuses paid to officers and employees of the Issuer to the
extent not in violation of the covenant described below in
the discussion entitled "Transactions with Affiliates";
- expenditures with respect to any non-cash compensation to
officers and employees of the Issuer and its Subsidiaries;
- amounts expended by the Issuer and its Subsidiaries on
selling, general and administrative expenses for Canadian
Abraxas and Old Grey Wolf; and
- the Stark Fees.
"SG&A ANNUAL AMOUNT" equals, for any annual calendar period, the
lesser of $5 million and the SG&A Budget.
"SG&A BUDGET" means, for any annual or quarter calendar period, as the
case may be, Closing SG&A Ratio multiplied by the Total Assets at the start of
such calendar period.
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"SG&A DEFICIT AMOUNT" means, for any calendar quarter, the amount by
which the SG&A in any such quarter (excluding the amount of SG&A due to any
Rollover Decrease because of a prior quarter's SG&A Excess Amount) is less than
the applicable SG&A Quarterly Amount.
"SG&A EXCESS AMOUNT" means, for any calendar quarter, the amount by
which SG&A in any such quarter (excluding the amount of SG&A due to any Rollover
Increase because of a prior quarter's SG&A Deficit Amount) exceeds the
applicable SG&A Quarterly Amount.
"SG&A QUARTERLY AMOUNT" means, for any calendar quarter, the lesser of
(a) $1.5 million and (b) one quarter of the SG&A Budget.
"SUBORDINATED INDEBTEDNESS" means Indebtedness of the Issuer or a
Subsidiary Guarantor that is subordinated or junior in right of payment to the
notes, the relevant Guarantee and the security documents, as applicable, under a
written agreement to that effect.
"SUBSIDIARY" means, with respect to any Person:
(1) any corporation of which the outstanding Capital Stock having at
least a majority of the votes entitled to be cast in the election of directors
under ordinary circumstances shall at the time be owned, directly or indirectly,
by such Person, or
(2) any other Person of which at least a majority of the voting
interests under ordinary circumstances is at the time, directly or indirectly,
owned by such Person, or
(3) any other Person required to be consolidated with such Person for
financial reporting purposes under GAAP.
"SUBSIDIARY GUARANTOR" means Sandia, Wamsutter, Sandia Operating,
Western Associated, Eastside Coal and New Grey Wolf and each of the Issuer's
Subsidiaries that in the future executes a supplemental indenture in which such
Subsidiary agrees to be bound by the terms of the indenture as a Subsidiary
Guarantor; PROVIDED, HOWEVER, that any Person constituting a Subsidiary
Guarantor as described above shall cease to constitute a Subsidiary Guarantor
when its Guarantee is released in accordance with the terms of the indenture.
"TOTAL ASSETS" means, as of any date, total assets of the Issuer and
its Subsidiaries as reflected on the Issuer's consolidated balance sheet as of
such date prepared in accordance with GAAP.
"TRUST MONEYS" means all cash or Cash Equivalents received by the
Trustee:
(1) upon the release of Collateral from the Lien of the indenture and
the security documents, including investment earnings thereon; or
(2) pursuant to the provisions of any Mortgage; or
(3) as proceeds of any other sale or other disposition of all or any
part of the Collateral by or on behalf of the Trustee or any collection,
recovery, receipt, appropriation or other realization of or from all or any part
of the Collateral pursuant to the indenture or any of the security documents or
otherwise; or
(4) for application under the indenture as provided for in the
indenture or the security documents, or whose disposition is not elsewhere
specifically provided for in the indenture or in the security documents;
PROVIDED, HOWEVER, that Trust Moneys shall not include any property
deposited with the Trustee pursuant to any Change of Control Offer, a payment to
Pay Down Debt or redemption or defeasance of any notes.
"WESTERN ASSOCIATED" means Western Associated Energy Corporation, a
Texas corporation.
"WAMSUTTER" means Wamsutter Holdings, Inc., a Wyoming corporation.
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"WEIGHTED AVERAGE LIFE TO MATURITY" means, when applied to any
Indebtedness at any date, the number of years obtained by dividing:
(1) the then outstanding aggregate principal amount of such
Indebtedness into
(2) the sum of the total of the products obtained by multiplying:
(a) the amount of each then remaining installment, sinking
fund, serial maturity or other required payment of principal,
including payment at final maturity, in respect thereof, by
(b) the number of years (calculated to the nearest
one-twelfth) which will elapse between such date and the making of
such payment.
"WHOLLY OWNED SUBSIDIARY" means any Subsidiary of which all the
outstanding voting securities normally entitled to vote in the election of
directors are owned by the Issuer or another Wholly Owned Subsidiary.
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DESCRIPTION OF CAPITAL STOCK
COMMON STOCK
Abraxas is currently authorized to issue up to 200,000,000 shares of
common stock, par value $.01 per share.
As of May 28, 2003 there were 35,630,115 shares of Abraxas common
stock issued and outstanding. Holders of the common stock are entitled to cast
one vote for each share held of record on all matters submitted to a vote of
stockholders and are not entitled to cumulate votes for the election of
directors. Holders of common stock do not have preemptive rights to subscribe
for additional shares of common stock issued by Abraxas.
Holders of the common stock are entitled to receive dividends as may
be declared by the Board of Directors out of funds legally available therefore.
Under the terms of the first lien notes indenture and the second lien notes
indenture, Abraxas may not pay dividends on shares of its common stock. In the
event of liquidation, holders of the common stock are entitled to share pro rata
in any distribution of Abraxas' assets remaining after payment of liabilities,
subject to the preferences and rights of the holders of any outstanding shares
of preferred stock. All of the outstanding shares of the common stock are fully
paid and nonassessable.
References herein to Abraxas' common stock include the common share
purchase rights distributed by Abraxas to its stockholders on November 17, 1994,
as long as they trade with the common stock. See "-- Stockholder Rights Plan"
beginning on page 132.
PREFERRED STOCK
Abraxas' Articles of Incorporation authorize the issuance of up to
1,000,000 shares of preferred stock, par value $.01 per share, in one or more
series. The Board of Directors is authorized, without any further action by the
stockholders, to determine the dividend rights, dividend rate, conversion
rights, voting rights, rights and terms of redemption, liquidation preferences,
sinking fund terms and other rights, preferences, privileges and restrictions of
any series of preferred stock, the number of shares constituting any such
series, and the designation thereof. The rights of the holders of common stock
will be subject to, and may be adversely affected by, the rights of holders of
any preferred stock that may be issued in the future.
WARRANTS
Abraxas has warrants outstanding to purchase an aggregate of 950,000
shares of Abraxas common stock. Basil Street Company has warrants to purchase
750,000 shares at an exercise price of $3.50 per share and Jesup & Lamont
Holdings, TNC, Inc. and Charles K. Butler (collectively "Jesup, et al") have
warrants to purchase 200,000 shares at $3.50 per share. Basil Street and Jesup,
et al have certain registration rights with respect to shares of the Abraxas
common stock issued pursuant to the exercise of such warrants.
All outstanding warrants contain provisions that protect Basil Street
and Jesup, et al against dilution by adjusting the price at which the warrants
are exercisable and the number of shares of the Abraxas common stock issuable
upon exercise thereof upon the occurrence of certain events, including payment
of stock dividends and distributions, stock splits, recapitalizations,
reclassifications, mergers or consolidations. A holder of warrants has no rights
as a stockholder of Abraxas until the warrants are exercised. All warrants are
currently exercisable, although none have been exercised as of the date hereof.
Under the terms of their warrants, Basil Street and Jesup, et al have
the right to unlimited piggyback registrations. Abraxas has agreed to pay all
expenses in connection with piggyback registrations by Basil Street and Jesup,
et al, provided, however, all underwriting discounts and selling commissions
shall be borne by Basil Street and Jesup, et al. The registration statement of
which this prospectus forms a part fulfills Abraxas' registration obligations
with respect to the holdings of Basil Street and Jesup, et al.
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OPTION PLANS
Pursuant to the ISO Plan, the 1993 Plan and the LTIP, Abraxas grants
to employees and officers (including Abraxas' directors who are also employees)
incentive stock options and non-qualified stock options. The ISO Plan, the 1993
Plan, and the LTIP are administered by the compensation committee which, based
upon the recommendation of the Chief Executive Officer, determines the number of
shares subject to each option. As of May 28, 2003, there were options to
purchase 3,293,302 shares of Abraxas common stock outstanding, of which
2,215,788 were fully vested at an average exercise price of $0.99 per share.
Effective as of the closing date of the exchange offer and subject to
any requirements under applicable law, the Abraxas Board of Directors has
approved a reduction in the exercise price of one-half of the options to
purchase Abraxas common stock held by Mr. Watson (320,282 options), and a
reduction in the exercise price of all of stock options previously issued to
other Abraxas employees (approximately 1.8 million options). The exercise price
on such options will be reduced to the price at which a share of Abraxas common
stock is trading on the American Stock Exchange at 11:00 a.m. New York time on
that date.
ANTI-TAKEOVER EFFECTS OF CERTAIN PROVISIONS OF THE ARTICLES OF INCORPORATION AND
BYLAWS
Abraxas' Articles of Incorporation and Bylaws provide for the Board of
Directors to be divided into three classes of directors serving staggered
three-year terms. As a result, approximately one-third of the Board of Directors
will be elected each year. The Articles of Incorporation and Bylaws provide that
the Board of Directors will consist of not less than three nor more than twelve
members, with the exact number to be determined from time to time by the
affirmative vote of a majority of directors then in office. The Board of
Directors, and not the stockholders, has the authority to determine the number
of directors. This provision could prevent any stockholder from obtaining
majority representation on Abraxas' Board of Directors by enlarging the Board of
Directors and by filling the new directorships with the stockholder's own
nominees. In addition, directors may be removed by the stockholders only for
cause.
The Articles of Incorporation and Bylaws provide that special meetings
of stockholders of Abraxas may be called only by the Chairman of the Board, the
President or a majority of the members of the Board of Directors. This provision
may make it more difficult for stockholders to take actions opposed by the Board
of Directors.
The Articles of Incorporation and Bylaws provide that any action
required to be taken or which may be taken by holders of Abraxas common stock
must be effected at a duly called annual or special meeting of such holders, and
may not be taken by any written consent of such stockholders. These provisions
may have the effect of delaying consideration of a stockholder proposal until
the next annual meeting unless a special meeting is called by the persons set
forth above. The provisions of the Articles of Incorporation and Bylaws
prohibiting stockholder action by written consent could prevent the holders of a
majority of the voting power of Abraxas from using the written consent procedure
to take stockholder action and taking action by consent without giving all the
stockholders of Abraxas entitled to vote on a proposed action the opportunity to
participate in determining such proposed action.
STOCKHOLDER RIGHTS PLAN
On November 17, 1994, the Board of Directors of Abraxas adopted a
stockholder rights plan (the "Stockholder Rights Plan"). Under the terms of the
Stockholder Rights Plan, the Board of Directors of Abraxas declared a dividend
of one common share purchase right ("Stockholder Right") on each share of the
Abraxas common stock outstanding on November 17, 1994. Each Stockholder Right
entitles the holder thereof to buy one share of Abraxas common stock at an
exercise price of $40 per share, subject to adjustment.
The Stockholder Rights are not exercisable until the occurrence of
specified events. Upon the occurrence of such an event (which events are
generally those which would signify the commencement of a hostile bid to acquire
Abraxas), the Stockholder Rights then become exercisable (unless redeemed by the
Board of Directors) for a number of shares of Abraxas common stock having a
market value of four times
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the exercise price of the Stockholder Right. If the acquirer were to conclude
the acquisition of Abraxas, the Stockholder Rights would then become exercisable
for shares of the controlling/surviving corporation having a value of four times
the exercise price of the Stockholder Rights. If the Stockholder Rights were
exercised at any time, significant dilution would result, thus making the
acquisition prohibitively expensive for the acquirer. In order to encourage a
bidder to negotiate with the Board of Directors, the Stockholder Rights Plan
provides that the Stockholder Rights may be redeemed under prescribed
circumstances by the Board of Directors.
The Stockholder Rights are not intended to prevent a takeover of
Abraxas and will not interfere with any tender offer or business combination
approved by the Board of Directors. The Stockholder Rights Plan is intended to
protect the stockholders in the event of (a) an unsolicited offer to acquire
Abraxas, including offers that do not treat all stockholders equally, (b) the
acquisition in the open market of shares constituting control of Abraxas without
offering fair value to all stockholders and (c) other coercive takeover tactics
which could impair the Board's ability to fully represent the interests of the
stockholders.
ANTI-TAKEOVER STATUTES
The Nevada General Corporation Law (the "Nevada GCL") contains two
provisions, described below as "Combination Provisions" and the "Control Share
Act," that may make more difficult the accomplishment of unsolicited or hostile
attempts to acquire control of a corporation through certain types of
transactions.
Restrictions on Certain Combinations Between Nevada Resident
Corporations and Interested Stockholders. The Nevada GCL includes certain
provisions (the "Combination Provisions") prohibiting certain "combinations"
(generally defined to include certain mergers, disposition of assets
transactions, and share issuance or transfer transactions) between a resident
domestic corporation and an "interested stockholder" (generally defined to be
the beneficial owner of 10% or more of the voting power of the outstanding
shares of the corporation), except those combinations which are approved by the
board of directors before the interested stockholder first obtained a 10%
interest in the corporation's stock. There are additional exceptions to the
prohibition, which apply to combinations if they occur more than three years
after the interested stockholder's date of acquiring shares. The Combination
Provisions apply unless the corporation elects against their application in its
original articles of incorporation or an amendment thereto, or in its bylaws.
Abraxas' Articles of Incorporation and Bylaws do not currently contain a
provision rendering the Combination Provisions inapplicable.
Nevada Control Share Act. Nevada's Control Share Acquisition Act (the
"Control Share Act") imposes procedural hurdles on and curtails greenmail
practices of corporate raiders. The Control Share Act temporarily
disenfranchises the voting power of "control shares" of a person or group
("Acquiring Person") purchasing a "controlling interest" in an "issuing
corporation" (as defined in the Nevada GCL) not opting out of the Control Share
Act. In this regard, the Control Share Act will apply to an "issuing
corporation" unless, before an acquisition is made, the articles of
incorporation or bylaws in effect on the tenth day following the acquisition of
a controlling interest provide that it is inapplicable. Abraxas' Articles of
Incorporation and Bylaws do not currently contain a provision rendering the
Control Share Act inapplicable.
Under the Control Share Act, an "issuing corporation" is a corporation
organized in Nevada which has 200 or more stockholders, at least 100 of whom are
stockholders of record (which for this purpose includes registered and
beneficial owners) and residents of Nevada, and which does business in Nevada
directly or through an affiliated company. The status of Abraxas at the time of
the occurrence of a transaction governed by the Control Share Act (assuming that
Abraxas' Articles of Incorporation or Bylaws have not theretofore been amended
to include an opting out provision) would determine whether the Control Share
Act is applicable.
The Control Share Act requires an Acquiring Person to take certain
procedural steps before he or it can obtain the full voting power of the control
shares. "Control shares" are the shares of a corporation (1) acquired or offered
to be acquired which will enable the Acquiring Person to own a "controlling
interest," and (2) acquired within 90 days immediately preceding that date. A
"controlling interest" is defined as the ownership of shares which would enable
the Acquiring Person to exercise certain graduated amounts
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(beginning with one-fifth) of all voting power of the corporation. The Acquiring
Person may not vote any control shares without first obtaining approval from the
stockholders not characterized as "interested stockholders" (as defined below).
To obtain voting Rights in control shares, the Acquiring Person must
file a statement at the principal office of the issuer ("Offeror's Statement")
setting forth certain information about the acquisition or intended acquisition
of stock. The Offeror's Statement may also request a special meeting of
stockholders to determine the voting Rights to be accorded to the Acquiring
Person. A special stockholders' meeting must then be held at the Acquiring
Person's expense within 30 to 50 days after the Offeror's Statement is filed. If
a special meeting is not requested by the Acquiring Person, the matter will be
addressed at the next regular or special meeting of stockholders.
At the special or annual meeting at which the issue of voting rights
of control shares will be addressed, "interested stockholders" may not vote on
the question of granting voting rights to control the corporation or its parent
unless the articles of incorporation of the issuing corporation provide
otherwise. Abraxas' Articles of Incorporation do not currently contain a
provision allowing for such voting power.
If full voting power is granted to the Acquiring Person by the
disinterested stockholders, and the Acquiring Person has acquired control shares
with a majority or more of the voting power, then (unless otherwise provided in
the articles of incorporation or bylaws in effect on the tenth day following the
acquisition of a controlling interest) all stockholders of record, other than
the Acquiring Person, who have not voted in favor of authorizing voting rights
for the control shares, must be sent a notice advising them of the fact and of
their right to receive "fair value" for their shares. Abraxas' Articles of
Incorporation and Bylaws do not provide otherwise. By the date set in the
dissenter's notice, which may not be less than 30 nor more than 60 days after
the dissenter's notice is delivered, any such stockholder may demand to receive
from the corporation the "fair value" for all or part of his shares. "Fair
value" is defined in the Control Share Act as "not less than the highest price
per share paid by the Acquiring Person in an acquisition."
The Control Share Act permits a corporation to redeem the control
shares in the following two instances, if so provided in the articles of
incorporation or bylaws of the corporation in effect on the tenth day following
the acquisition of a controlling interest: (1) if the Acquiring Person fails to
deliver the Offeror's Statement to the corporation within 10 days after the
Acquiring Person's acquisition of the control shares; or (2) an Offeror's
Statement is delivered, but the control shares are not accorded full voting
rights by the stockholders. Abraxas' Articles of Incorporation and Bylaws do not
address this matter.
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REGISTRATION RIGHTS; LIQUIDATED DAMAGES
SHELF REGISTRATION
Pursuant to the registration rights agreement that we entered into
with Jefferies & Company, Inc., acting on behalf of the holders of the notes and
shares of common stock covered by this prospectus, we have filed a shelf
registration statement of which this prospectus is a part, covering resales of
the notes, any additional notes issued in lieu of cash interest payments and the
shares of Abraxas common stock issued in the financial restructuring exchange
offer. We will be permitted to withdraw the registration statement upon the
soonest of (1) the passage of two years following the date of closing of this
exchange offer, (2) the date on which all tendering noteholders have disposed of
all of the securities covered by such shelf registration statement, or (3) the
date that Jefferies & Company receives an opinion of counsel to Abraxas and the
guarantors that all of the securities covered by such shelf registration
statement may be sold under the provisions of Rule 144 without limitation as to
volume or manner of sale.
If the registration statement of which this prospectus is a part
ceases to be effective or usable in connection with exchange or resales of the
notes, any additional notes issued in lieu of cash interest payments, and the
common stock during the periods specified in the registration rights agreement
(and as qualified by the exceptions described in such agreement), or if we fail
to meet other obligations under the registration rights agreement, then, as
liquidated damages for such default under the registration rights agreement, the
interest rate on the notes and any additional notes issued in lieu of cash
interest payments, with respect to the first 90 day period immediately following
the occurrence of such default under the registration rights agreement will
increase, by 3.5% per annum and will increase by an additional 0.5% per annum
with respect to each subsequent 30 day period until all such defaults have been
cured, up to a maximum per annum interest rate on such notes of 18% with respect
to all defaults under the registration rights agreement. All accrued liquidated
damages will be paid by Abraxas in the same manner and at the same time as
payments of interest on the notes and any additional notes issued in lieu of
cash interest payments. Following the cure of all defaults under the
registration rights agreement, the accrual of liquidated damages will cease. No
liquidated damages will be payable to holders of the common stock who do not
otherwise hold notes.
With respect to the shelf registration statement of which this
prospectus is a part, holders of any securities to be covered by such
registration statement are required to deliver information to be used in
connection with the registration statement in order to have their securities
included in the registration statement and to benefit from the provisions
regarding liquidated damages set forth above, to the extent applicable. We are
not responsible for the failure of a selling security holder to provide accurate
information in connection with this prospectus.
EXCHANGE OFFER REGISTRATION
Pursuant to the registration rights agreement, we have also filed with
the SEC a registration statement with respect to an offer to exchange the notes
covered by this prospectus and any additional notes issued in lieu of cash
interest payments for a new issue of notes registered under the Securities Act,
with terms identical in all material respects to those of the outstanding notes.
We have agreed that if we are not permitted to consummate the exchange offer or
if fewer than all of the outstanding notes are successfully exchanged in the
exchange offer, that we will use our reasonable best efforts to maintain the
effectiveness of the shelf registration statement of which this prospectus is a
part to cover the resales of such notes remaining outstanding. To the extent
that outstanding notes are exchanged in the exchange offer for registered notes,
such outstanding notes will be removed from this prospectus.
This summary of the registration rights agreement is subject to, and
is qualified in its entirety by reference to, all the provisions of the
registration rights agreement, a copy of which is filed as an exhibit to the
shelf registration statement of which this prospectus is a part.
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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
SCOPE AND LIMITATIONS
The following general discussion summarizes certain United States
federal income tax aspects of the ownership of the notes and Abraxas common
stock. This discussion is a summary for general information purposes only, and
does not purport to describe all of the United States federal income tax
consequences resulting from the acquisition, ownership and disposition of notes
and Abraxas common stock nor does it describe United States federal income tax
consequences resulting to Non-U.S. Holders, except as expressly indicated. This
summary deals only with notes and Abraxas common stock that are held as capital
assets by a purchaser and does not deal with special situations, such as those
of brokers, dealers in securities or currencies, financial institutions,
tax-exempt entities, insurance companies, persons liable for alternative minimum
tax, United States persons whose "functional currency" is not the U.S. dollar,
persons holding the notes as part of a hedging, integrated, conversion or
constructive sale transaction or a straddle, and traders in securities that
elect to use a mark-to-market method of accounting for their securities
holdings. The following summary does not address any state, local or non-United
States tax consequences or United States federal tax consequences (e.g., estate
or gift tax) other than those pertaining to the income tax.
Furthermore, this discussion is based on provisions of the Internal
Revenue Code of 1986, as amended (the "Code"), the Treasury Regulations
promulgated thereunder, and administrative and judicial interpretations of the
foregoing, all as in effect as of the date hereof and all of which are subject
to change, possibly with retroactive effect. This discussion will not be binding
in any manner on the Internal Revenue Service (the "IRS") or the courts. No
ruling has been or will be requested from the IRS on any of the matters relating
to holding the notes and Abraxas common stock, and no assurance can be given
that the IRS will not successfully challenge certain of the conclusions set
forth below. If a partnership holds the notes and/or Abraxas common stock, the
tax treatment of a partner will generally depend upon the status of the partner
and the activities of the partnership. Partners of partnerships that hold notes
and/or Abraxas common stock, should consult their own tax advisors.
As used herein, the term "U.S. Holder" means a holder of notes or
Abraxas common stock that is, for United States federal income tax purposes:
(1) an individual who is a citizen or resident of the United
States;
(2) a corporation or partnership created or organized in or
under the law of the United States or of any political
subdivision thereof;
(3) an estate, the income of which is includible in gross income
for United States federal income tax purposes regardless of
its source; or
(4) a trust if (a) a United States court is able to exercise
primary supervision over the administration of the trust and
one or more United States persons have the authority to
control all substantial decisions of the trust, or (b) the
trust was in existence on August 20, 1996, was treated as a
United States person prior to that date, and elected to
continue to be treated as a United States person.
For purposes of this discussion, the term "non-U.S. Holder" means any
person other than a U.S. Holder.
EACH U. S. HOLDER, NON-U.S. HOLDER, PROSPECTIVE U.S. HOLDERS AND PROSPECTIVE
NON-U.S. HOLDERS SHOULD CONSULT THEIR TAX ADVISORS REGARDING THE PARTICULAR U.S.
FEDERAL INCOME TAX CONSEQUENCES TO SUCH HOLDER OR PROSPECTIVE HOLDER OF THE
PURCHASE, OWNERSHIP AND DISPOSITION OF THE NOTES AND/OR ABRAXAS COMMON STOCK, AS
WELL AS ANY TAX CONSEQUENCES THAT MAY ARISE UNDER THE LAWS OF ANY OTHER RELEVANT
FOREIGN, STATE, LOCAL OR OTHER TAXING JURISDICTION.
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TAX CONSEQUENCES TO U.S. HOLDERS
ORIGINAL ISSUE DISCOUNT ON THE NOTES. In general, subject to a de
minimis rule, a debt obligation will be treated as being issued with original
issue discount ("OID") if the "stated redemption price at maturity" of the
instrument exceeds that instrument's "issue price"(as described below in "Issue
Price").
The stated redemption price at maturity of a debt obligation is the
aggregate of all payments due to the U.S. Holder under that debt obligation at
or prior to its maturity date, other than interest that is actually and
unconditionally payable in cash or property (other than debt instruments of the
issuer) at a single fixed (or a qualified floating) rate (or a permitted
combination of the two) at least annually ("QSIPs"). Interest on the notes will
be payable in cash, except that Abraxas may, subject to certain conditions, pay
the interest due on any interest payment date through and including the maturity
date of the notes by the issuance of additional notes ("PIK notes"). Because the
interest on the notes due on any payment date may be paid through the issuance
of additional PIK notes, none of the interest payments on the notes will qualify
as QSIPs. Thus, the stated redemption price at maturity of the notes will
include all payments of principal and all of the interest required under the
notes. Furthermore, under the regulations issued pursuant to the OID provisions
of the Code (the "OID Regulations"), a note and any PIK notes issued with
respect thereto are treated as part of the same debt instrument. Accordingly,
the adjusted issue price of the combined note and PIK note will not be reduced
upon the issuance of the PIK note, and the stated redemption price at maturity
of the combined note and PIK note will not change upon the issuance of the PIK
note and will include the interest payable under the PIK note.
Since the stated redemption price at maturity of the notes exceeds
their issue price, the notes were issued with OID. A U.S. Holder of notes,
subject to the adjustments discussed below, will be required to include in gross
income for federal income tax purposes the sum of the daily portions of OID for
each day during the taxable year or portion thereof during which the U.S. Holder
holds the notes, whether or not the U.S. Holder actually receives a payment
relating to OID in such year. The daily portion is determined by allocating to
each day of the relevant "accrual period" a pro rata portion of an amount equal
to (a) the product of (1) the "adjusted issue price" of the notes at the
beginning of each accrual period, multiplied by (2) the yield to maturity of the
notes (determined by semi-annual compounding) less (b) the sum of any QSIPs
during the accrual period. The "adjusted issue price" of a note at any given
time is its issue price increased by all accrued OID for prior accrual periods
(without regard to the acquisition premium rules) and decreased by the amount of
any payment previously made on the notes other than a QSIP. As discussed above,
only a portion of the interest payments on the notes will qualify as QSIPs.
A U.S. Holder of a note will be required to include OID in income as
such OID accrues, regardless of the U.S. Holder's method of accounting and
regardless of when such U.S. Holder receives cash payments relating to the OID.
A U.S. Holder's tax basis in a note will be increased by the amount of OID
included in the U.S. Holder's income and reduced by the portion of all interest
payments not qualifying as QSIPs (other than payments in the form of PIK notes)
received on the notes.
The computation of OID and adjusted issue price with respect to the
combined notes and PIK notes will take into account accruals and payments with
respect to both instruments, with the result that the U.S. Holder of a note
generally will be required to include in income as OID the portion of interest
that accrues under the note that does not give rise to QSIPs and the interest
that accrues under any PIK note issued in respect thereof, regardless of whether
any cash payments are received. Each U.S. Holder of a note will be required to
include in income cash payments of stated interest qualifying as QSIPs in
accordance with their regular method of accounting.
Upon a disposition of a note or a PIK note issued in respect thereof,
the U.S. Holder will be required (unless it disposes of a note together with all
PIK notes issued in respect thereof) to allocate adjusted issue price, stated
redemption price at maturity and acquisition premium (discussed below), if any,
of the combined note and PIK note among the instruments retained and the
instruments disposed of in order to determine OID with respect to the retained
instruments. Although it is not clear, it is likely that the adjusted tax basis
and adjusted issue price of a note would be allocated between such note and any
PIK notes issued with respect thereto at the time of such issuance, based on
their respective principal amounts. OID on the PIK notes will accrue in the same
manner as described above in respect of the notes.
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A purchaser of a note who purchases the note at a cost less than the
remaining stated redemption price at maturity but greater than its adjusted
issue price (a purchase at an "acquisition premium") also will be required to
include in gross income the sum of the daily portions of OID on that note. (For
purposes of these rules, a "purchase" is any acquisition of a debt instrument.)
In computing the daily portions of OID for such a purchaser, however, the daily
portion is reduced by the amount that would be the daily portion for such day
(computed in accordance with the rules set forth above) multiplied by a
fraction, the numerator of which is the amount, if any, by which the purchaser's
basis in the note on the date of purchase exceeds the adjusted issue price of
the note at that time, and the denominator of which is the sum of the daily
portions for that notes for all days beginning on the day after the purchase
date and ending on the maturity date.
Abraxas will furnish annually to the IRS, and to each U.S. Holder of
notes to whom Abraxas is required to report, information relating to the OID
accruing during the calendar year. U.S. Holders will be required to determine
for themselves whether, by reason of the rules described above, they are
eligible to report a reduced amount of OID for federal income tax purposes.
Pursuant to the OID Regulations, U.S. Holders of debt instruments are
permitted to elect to include all interest, discount (including de minimis
market discount) and premium on a debt instrument in income currently on a
constant yield to maturity basis. Such election would constitute an election to
include market discount currently in income on all market discount bonds held by
such U.S. Holders. U.S. Holders of notes are urged to consult their own tax
advisors regarding the availability and advisability of making such an election.
ISSUE PRICE. The "issue price" of the notes was determined by
reference to the fair market value of the second lien notes and old notes for
which they were exchanged pursuant to the exchange offer. The fair market value
of the second lien notes and old notes was allocated based upon the relative
fair market value of the consideration received by Holders pursuant to the
exchange offer. Information regarding the issue price of the notes may be
obtained by sending a request in writing addressed to the Chief Financial
Officer of Abraxas Petroleum Corporation at 500 North Loop 1604, Suite 100, San
Antonio, Texas 78232.
SALE, EXCHANGE OR REDEMPTION OF NOTES. As noted above, the OID
Regulations treat a note and any PIK notes issued with respect thereto as a part
of the same debt instrument. If, however, a U.S. Holder disposes of a note or a
PIK note separately, in order to determine the amount of its gain or loss
recognized, the U.S. Holder will be required to allocate adjusted issue price
and acquisition premium of the combined note and the PIK notes issued with
respect thereto among the debt instruments retained and disposed of, as
described above. See "--Original Issue Discount on the Notes" above.
Under the OID Regulations, an unscheduled payment made on a debt
instrument such as a note prior to maturity that results in a substantially pro
rata reduction of each payment of principal and interest remaining on the
instrument is treated as a payment in retirement of a portion of the instrument,
which may result in gain or loss to the U.S. Holder. The gain or loss is
calculated by treating the debt obligation as consisting of two instruments, one
that is retired and one that remains outstanding, and by allocating the adjusted
issue price and the U.S. Holder's adjusted basis between the two instruments
based upon the relative principal amount of the portion of the obligation that
is treated as retired by the pro rata prepayment. The stated redemption price at
maturity of and the OID on the remaining instrument will be determined according
to the same principles discussed above. See "--Original Issue Discount on the
Notes" above.
Except as discussed above, upon the sale, exchange or retirement of a
note, a U.S. Holder generally will recognize taxable gain or loss equal to the
difference between the amount realized on the sale, exchange or retirement of
the note (other than amounts representing accrued and unpaid interest) and such
U.S. Holder's adjusted tax basis in the note. A U.S. Holder's adjusted tax
basis in a note generally will equal such U.S. Holder's initial investment in
the note increased by any original issue discount included in income and any
accrued market discount included in income, decreased by the amount of any
payments that are not deemed qualified stated interest payments and amortizable
bond premium applied to reduce interest with respect to such note. Such gain or
loss generally will be long term capital gain or loss if the note has been held
for more than one year at the time of such sale, exchange or retirement.
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ACCRUED MARKET DISCOUNT. A debt instrument has "market discount" if
its stated redemption price at maturity exceeds its tax basis in the hands of
the U.S. Holder immediately after its acquisition, unless a statutorily defined
de minimis exception applies. Any gain recognized on the maturity or disposition
of a note will be treated as ordinary income to the extent that such gain does
not exceed the accrued market discount on such note. Alternatively, a U.S.
Holder of a note may elect to include market discount in income currently over
the life of the note. Such election shall apply to all debt instruments with
market discount acquired by the electing U.S. Holder on or after the first day
of the first year to which the election applies and may not be revoked without
the consent of the IRS.
AMORTIZABLE BOND PREMIUM. Generally, a U.S. Holder of a note has
"amortizable bond premium" to the extent that the purchase price of a note
exceeds the note 's stated redemption price at maturity. Such a note will not be
treated as issued with OID. If the U.S. Holder makes (or has made) a timely
election under Section 171 of the Code, such U.S. Holder may amortize the bond
premium, on a constant yield basis, by offsetting the interest income from the
notes.
If the U.S. Holder of a note makes an election to amortize bond
premium, the tax basis of the debt instrument must be reduced by the amount of
the aggregate amortization deductions allowable for the bond premium. Any such
election to amortize bond premium would apply to all debt instruments held or
subsequently acquired by the electing U.S. Holder and cannot be revoked without
permission from the IRS.
BACKUP WITHHOLDING. A U.S. Holder of a note may be subject to backup
withholding at the rate of 31% with respect to "reportable payments," which
include payments in respect of interest or accrued OID, and the proceeds of a
sale, exchange or redemption of a note. Abraxas will be required to deduct and
withhold the prescribed amount if (a) the U.S. Holder fails to furnish a
taxpayer identification number ("TIN") to Abraxas in the manner required, (b)
the IRS notifies Abraxas that the TIN furnished by the U.S. Holder is incorrect,
(c) there has been a failure of the U.S. Holder to certify under penalty of
perjury that the U.S. Holder is not subject to withholding under Section
3406(a)(1)(C) of the Tax Code, or (d) the U.S. Holder is notified by the IRS
that he or she failed to report properly payments of interest and dividends and
the IRS has notified Abraxas that he or she is subject to backup withholding.
Amounts paid as backup withholding do not constitute an additional tax
and will be credited against the U.S. Holder's U.S. federal income tax
liabilities, so long as the required information is provided to the IRS. Abraxas
will report to the U.S. Holders of notes and to the IRS the amount of any
"reportable payments" for each calendar year and the amount of tax withheld, if
any, with respect to payments on such notes to any noncorporate U.S. Holder
other than an "exempt recipient."
THE TAX RULES GOVERNING INSTRUMENTS ISSUED WITH OID AND THE DISCUSSION ABOVE
UNDER "--ORIGINAL ISSUE DISCOUNT ON THE NOTES," "SALE, EXCHANGE AND RETIREMENT
OF NOTES," "ACCRUED MARKET DISCOUNT" AND "AMORTIZABLE BOND PREMIUM" ARE COMPLEX
AND THEIR APPLICATION TO A U.S. HOLDER WILL DEPEND UPON SUCH U.S. HOLDER'S
INDIVIDUAL SITUATION. U.S. HOLDERS ARE URGED TO CONSULT THEIR TAX ADVISOR ABOUT
THE APPLICATION OF THESE RULES TO THE THEM.
TAX CONSEQUENCES OF HOLDING COMMON STOCK
RULES GENERALLY RELATING TO DISTRIBUTIONS WITH RESPECT TO STOCK. When
a corporation makes a distribution with respect to its capital stock, the amount
of the distribution received by the stockholder will be treated as a dividend
which will be taxable to the stockholder as ordinary income, to the extent it is
paid from the current or accumulated earnings and profits of the corporation.
The amount of a distribution made in property other than cash is the fair market
value of that property at the time of the distribution. U.S. Holders that are
corporations are entitled to a dividends-received deduction subject to certain
limitations. Earnings and profits for this purpose consists of an amount based
on the taxable income of the corporation as adjusted by the application of
detailed rules set forth in Treasury Regulations. A distribution will be treated
as a dividend even though we have an overall deficit in our earnings and profits
to the extent we have positive earnings and profits in the year in which we make
the distribution (i.e., current earnings and profits). If the amount of a
distribution exceeds the current and accumulated earnings and profits of the
corporation, the excess will be treated first as a tax-free return of investment
up to the basis of the stock,
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and this amount will reduce the stockholder's tax basis in the stock. If the
distribution exceeds the current and accumulated earnings and profits, and the
stockholder's tax basis in the stock, this excess amount will be treated as
capital gain to the stockholder. If the stockholder is a U.S. corporation, the
stockholder would generally be able to claim a deduction equal to a portion of
the amount of the distribution treated as a dividend, subject to certain
requirements under the Code, in accordance with the foregoing rules.
REDEMPTION OF COMMON STOCK. Upon redemption of the common stock by
Abraxas for cash or property other than capital stock, the redemption should be
treated as a sale or exchange under Section 302 of the Code and the tendering
holder should recognize capital gain or loss to the extent the redemption
proceeds are greater or less than the holder's adjusted tax basis in the common
stock if the redemption proceeds received in exchange for the common stock:
- are not essentially equivalent to a dividend distribution;
- are substantially disproportionate with respect to the
tendering holder;
- completely terminate the holder's equity interest in
Abraxas; or
- are distributed to an individual U.S. Holder as part of a
partial liquidation of shares (as defined in Section 302 of
the Code).
In determining whether a cash redemption qualifies for sale or exchange
treatment under Section 302 of the Code, a tendering U.S. Holder must take into
account shares of Abraxas stock that are actually owned by the tendering holder
and, in certain situations, shares that such U.S. Holder is deemed to own
through a related person or entity.
If the redemption does not qualify for sale or exchange treatment
under Section 302 of the Code, the redemption proceeds will be treated as a
distribution with respect to the common stock. The distribution will be taxable
as a dividend to the extent of current or accumulated earnings and profits. The
amount of the distribution in excess of current or accumulated earnings and
profits will be treated as a tax-free return of basis to the extent of the
tendering U.S. Holder's basis in its common stock and as capital gain to the
extent the distribution exceeds its basis in the common stock.
SALE OF COMMON STOCK. U.S. Holders will generally recognize capital
gain or loss on a sale or exchange of common stock. The gain or loss will equal
the difference between the proceeds received and the adjusted tax basis in the
stock. The gain or loss recognized by a U.S. Holder on a sale or exchange of
stock will be long-term capital gain or loss if the holding period for the stock
is more than one year.
NON-U.S. HOLDERS
Subject to the discussion of backup withholding below, the interest
income and gains that a non-U.S. Holder derives in respect of holding notes and
Abraxas common stock generally will be exempt from United States federal income
taxes, including withholding tax.
Payments of interest or principal in respect of the notes by Abraxas
or the paying agent to a holder that is a non-U.S. Holder will not be subject to
withholding of United States federal income tax, provided that, in the case of
payments of interest (including OID):
(1) the income is effectively connected with the conduct by such
non-U.S. Holder of a trade or business carried on in the
United States and the non-U.S. Holder complies with
applicable identification requirements (described below
under "Backup Withholding and Information Reporting"); or
(2) the non-U.S. Holder and/or each securities clearing
organization, bank, or other financial institution that
holds the notes on behalf of such non-U.S. Holder in the
ordinary course of its trade or business, in the chain
between the non-U.S. Holder and the paying agent, complies
with applicable identification requirements (described below
under "Backup Withholding and Information Reporting") to
establish that the holder is a non-U.S. Holder and in
addition, that the following requirements of the "portfolio
interest" exemption under the Code are satisfied:
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- the non-U.S. Holder does not actually or constructively own
10% or more of the voting stock of Abraxas;
- the non-U.S. Holder is not a controlled foreign corporation
with respect to Abraxas; and
- the non-U.S. Holder is not a bank whose receipt of interest
on the notes is described in Section 881(c)(3)(A) of the
Code.
Any gain realized by a non-U.S. Holder on the sale or exchange of the
notes, or Abraxas common stock generally will be exempt from U.S. federal income
tax, including withholding tax, unless:
(1) such gain is effectively connected with the conduct of a
trade or business in the United States (or if a tax treaty
applies, such gain is attributable to a permanent
establishment of the non-U.S. Holder);
(2) in the case of a non-U.S. Holder that is an individual, such
non-U.S. Holder is present in the United States for 183 days
or more during the taxable year in which such sale,
exchange, or other disposition occurs; or
(3) in the case of gain representing accrued interest, the
requirements of the portfolio interest exemption are not
satisfied.
If the interest income (including OID) paid on the notes or gain
recognized from a sale or exchange of the notes, or Abraxas common stock, is
effectively connected with the conduct of a trade or business in the United
States by a non-U.S. Holder, such non-U.S. Holder will generally be taxed under
the same rules that govern the taxation of a U.S. Holder. In addition, if such
holder is a foreign corporation, it may be subject to an additional branch
profits tax.
BACKUP WITHHOLDING AND INFORMATION REPORTING
Payment of the proceeds of a sale of a note or payment of interest
(including original issue discount) will be subject to information reporting
requirements and backup withholding tax unless the beneficial owner certifies
its non-United States status under penalties of perjury or otherwise establishes
an exemption provided that the paying agent does not actually know, or has
reason to know, that the holder is actually a U.S. Holder). Recently promulgated
Treasury Regulations provide certain presumptions under which a non-U.S. Holder
will be subject to backup withholding and information reporting unless such
holder certifies as to its non-U.S. status or otherwise establishes an
exemption. In addition, the recent Treasury Regulations change certain
procedural requirements related to establishing a holder's non-United States
status. Non-U.S. Holders should consult with their tax advisors regarding the
above issues.
Any amounts withheld from a payment to a non-U.S. Holder under the
backup withholding rules will be allowed as a credit against the holder's United
States federal income tax liability and may entitle the holder to a refund,
provided that the required information is furnished to the Internal Revenue
Service.
Applicable identification requirements generally will be satisfied if
there is delivered to a securities clearing organization either directly, or
indirectly, by the appropriate filing of a Form W-8IMY:
(1) IRS Form W-8BEN signed under penalties of perjury by the
non-U.S. Holder, stating that such holder of the notes is
not a United States person and providing such non-U.S.
Holder's name and address;
(2) with respect to non-U.S. Holders of the notes residing in a
country that has a tax treaty with the United States who
seek an exemption or reduced tax rate (depending on the
treaty terms), Form W-8BEN. If the treaty provides only for
a reduced rate, withholding tax will be imposed at that rate
unless the non-U.S. Holder qualifies under the portfolio
interest rules set forth in the Code and files a W-8BEN; or
(3) with respect to interest income "effectively connected" with
the conduct by such non-U.S. Holder of a trade or business
carried on in the United States, Form W-8ECI;
provided that in any such case:
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- the applicable form is delivered pursuant to applicable
procedures and is properly transmitted to the United States
withholding agent, otherwise required to withhold tax; and
- none of the entities receiving the form has actual knowledge
or reason to know that the holder is a U.S. Holder.
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LEGAL MATTERS
The validity of the issuance of the notes and the Abraxas common stock
covered by this prospectus has been passed upon for Abraxas by Cox & Smith
Incorporated, San Antonio, Texas.
EXPERTS
The consolidated financial statements of Abraxas as of December 31,
2002 and 2001, and for each of the three years in the period ended December 31,
2002, included in this prospectus have been audited by Deloitte & Touche LLP,
independent auditors, as stated in their report dated March 10, 2003, July 18,
2003 as to Note 20 and the first paragraph of "New Accounting Pronouncements" in
Note 1, appearing herein (which report expresses an unqualified opinion and
includes two explanatory paragraphs referring to subsequent events described in
Note 2 and the restatement described in Note 20), and have been so included in
reliance upon the report of such firm given upon their authority as experts in
accounting and auditing.
The consolidated financial statements of Grey Wolf Exploration Inc. as
of December 31, 2002 and 2001, and for each of the three years in the period
ended December 31, 2002, included in this prospectus have been audited by
Deloitte & Touche LLP, independent auditors, as stated in their report appearing
herein (which report expresses an unqualified opinion and includes an
explanatory paragraph relating to their previously issued report on the 2000
financial statements of Grey Wolf Exploration Inc. which excluded differences
between Canadian and United States generally accepted accounting principles),
and have been so included in reliance upon the report of such firm given upon
their authority as experts in accounting and auditing.
The historical reserve information prepared by DeGolyer and
MacNaughton and McDaniel and Associates Consultants Ltd. included in this
prospectus has been included herein in reliance upon the authority of such firm
as experts with respect to matters contained in such reserve reports.
WHERE YOU CAN FIND MORE INFORMATION
Abraxas and the guarantors of the notes have filed the registration
statement regarding the notes and Abraxas common stock with the SEC. This
prospectus does not contain all of the information included in the registration
statement. Any statement made in this prospectus concerning the contents of any
other document is not necessarily complete. If we have filed any other document
as an exhibit to the registration statement, you should read the exhibit for a
more complete understanding of the document or matter. Each statement regarding
any other document does not necessarily contain all of the information important
to you.
Abraxas files annual, quarterly and special reports, proxy statements
and other information with the SEC. Our SEC filings are available to the public
over the Internet at the SEC's website at http://www.sec.gov. You may also read
and copy any document Abraxas files at the SEC's public reference room at 450
Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the
operation of the SEC's public reference room in Washington, D.C. by calling the
SEC at 1-800-SEC-0330.
143
<Page>
GLOSSARY OF TERMS
Unless otherwise indicated in this prospectus, natural gas volumes are
stated at the legal pressure base of the State or area in which the reserves are
located at 60 degrees Fahrenheit. Natural gas equivalents are determined using
the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or
NGLs.
The following definitions shall apply to the technical terms used in
this prospectus.
TERMS USED TO DESCRIBE QUANTITIES OF CRUDE OIL AND NATURAL GAS
"BBL" -- barrel or barrels.
"BCF" -- billion cubic feet.
"BCFE" -- billion cubic feet equivalent.
"BOE" -- barrels of
"BOPD" -- barrels of crude oil per day.
"MBBL" -- thousand barrels.
"MCF" -- thousand cubic feet.
"MCFE" -- thousand cubic feet equivalent.
"MMBBLS" -- million barrels.
"MMBTU" -- million British Thermal Units.
"MMBTUPD" -- million British Thermal Units per day.
"MMCF" -- million cubic feet.
"MMCFE" -- million cubic feet equivalent.
"MMCFPD" -- million cubic feet per day.
TERMS USED TO DESCRIBE OUR INTERESTS IN WELLS AND ACREAGE
"DEVELOPED ACREAGE" means acreage which consists of acres spaced or
assignable to productive wells.
"GROSS" natural gas and crude oil wells or "gross" wells or acres is
the number of wells or acres in which we have an interest.
"NET" natural gas and crude oil wells or "net" acres are determined by
multiplying "gross" wells or acres by our working interest in such
wells or acres.
"UNDEVELOPED ACREAGE" means leased acres on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of crude oil and natural gas, regardless whether
or not such acreage contains proved reserves.
TERMS USED TO ASSIGN A PRESENT VALUE TO OR TO CLASSIFY OUR RESERVES
"PV-10" means estimated future net revenue, discounted at a rate of
10% per annum, before income taxes and with no price or cost
escalation or de-escalation in accordance with guidelines promulgated
by the SEC.
"PROVED RESERVES" or "RESERVES" means natural gas and crude oil,
condensate and NGLs on a net revenue interest basis, found to be
commercially recoverable.
"PROVED UNDEVELOPED RESERVES" includes those proved reserves expected
to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required for
recompletion.
144
<Page>
TERMS USED TO DESCRIBE COSTS
"DD&A" means depletion, depreciation and amortization.
"LOE" means lease operating expenses and production taxes.
TERMS USED TO DESCRIBE TYPES OF WELLS
"DEVELOPMENT WELL" means a well drilled within the proved area of a
crude oil or natural gas reservoir to the depth of stratigraphic
horizon (rock layer or formation) known to be productive for the
purpose of extraction of proved crude oil or natural gas reserves.
"DRY HOLE" means an exploratory or development well found to be
incapable of producing either crude oil or gas in sufficient
quantities to justify completion as a crude oil or natural gas well.
"EXPLORATORY WELL" means a well drilled to find and produce crude oil
or natural gas in an unproved area, to find a new reservoir in a field
previously found to be producing crude oil or natural gas in another
reservoir, or to extend a known reservoir.
"PRODUCTIVE WELLS" mean producing wells and wells capable of
production.
"SERVICE WELL" is a well used for water injection in secondary
recovery projects or for the disposal of produced water.
OTHER TERMS
"CHARGE" means an encumbrance, lien, claim or other interest in
property securing payment or performance of an obligation.
"EBITDA" means earnings from before income taxes, interest expense,
DD&A and other non-cash charges.
"NGL" means natural gas liquid.
"NYMEX" means the New York Mercantile Exchange.
145
<Page>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<Table>
<Caption>
Page
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
Independent Auditors' Reports for the years ended December 31, 2000, 2001 and 2002..................F-2
Consolidated Balance Sheets at December 31, 2001 and 2002 (Restated)................................F-3
Consolidated Statements of Operations for the years ended December 31, 2000,
2001 and 2002 (Restated).........................................................................F-5
Consolidated Statements of Stockholders' Equity (Deficit) for the years ended
December 31, 2000, 2001 and 2002.................................................................F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2000,
2001 and 2002. (Restated) .......................................................................F-8
Notes to Consolidated Financial Statements .........................................................F-10
Unaudited Condensed Consolidated Balance Sheets - March 31, 2003
and December 31, 2002 (Restated).................................................................F-44
Unaudited Condensed Consolidated Statements of Operations -
Three Months Ended March 31, 2003 and 2002 (Restated)............................................F-46
Unaudited Condensed Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002 (Restated)............................................F-47
Notes to Unaudited Condensed Consolidated Financial Statements......................................F-48
GREY WOLF EXPLORATION INC.
Auditors' Reports for the years ended December 31, 2000, 2001 and 2002..............................F-60
Comments by Auditors' for US readers on Canada - US reporting differences...........................F-61
Balance Sheets at December 31, 2002 and 2001........................................................F-62
Statements of Earnings and Retained Earnings for the years ended December 31, 2002, 2001
and 2000.........................................................................................F-63
Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000.......................F-64
Notes to Financial Statements.......................................................................F-65
</Table>
F-1
<Page>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and Subsidiaries (the "Company") as of December 31, 2002
and 2001, and the related consolidated statements of operations, stockholders'
equity (deficit), and cash flows for each of the three years in the period ended
December 31, 2002. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2002
and 2001, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2002 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, on January 23, 2003, the
Company sold all of the outstanding common stock of two wholly owned
subsidiaries, Canadian Abraxas Petroleum Limited and Grey Wolf Exploration,
Inc., repaid certain debt, and also entered into an agreement to exchange cash,
new debt and common stock of the Company for certain other debt.
As discussed in Note 20 to the financial statements, the accompanying 2000, 2001
and 2002 financial statements have been restated.
/s/DELOITTE & TOUCHE LLP
San Antonio, Texas
March 10, 2003 (July 18, 2003, as to Note 20 and the first paragraph of "New
Accounting Pronouncements" in Note 1)
F-2
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<Table>
<Caption>
(AS RESTATED, SEE NOTE 20)
---------------------------
DECEMBER 31
---------------------------
2001 2002
------------ -------------
(Dollars in thousands)
Current assets:
Cash ................................................................... $ 7,605 $ 4,882
Accounts receivable: ...................................................
Joint owners ...................................................... 2,785 2,215
Oil and gas production sales ...................................... 4,758 7,466
Other ............................................................. 504 364
------------ -------------
8,047 10,045
Equipment inventory .................................................... 1,251 1,014
Other current assets ................................................... 443 1,240
------------ -------------
Total current assets ................................................. 17,346 17,181
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................................ 486,098 521,995
Unproved, not subject to amortization ............................. 10,626 7,052
Other property and equipment ......................................... 67,632 44,189
------------ -------------
Total ........................................................... 564,356 573,236
Less accumulated depreciation, depletion, and amortization ........... 282,462 422,842
------------ -------------
Total property and equipment - net ................................ 281,894 150,394
Deferred financing fees, net of accumulated amortization of $8,668 and
$10,763 at December 31, 2001 and 2002, respectively .................... 3,928 5,671
Deferred income taxes ..................................................... - 7,820
Other assets .............................................................. 448 359
------------ -------------
Total assets ........................................................... $ 303,616 $ 181,425
============ =============
</Table>
See accompanying Notes to Consolidated Financial Statements
F-3
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<Table>
<Caption>
(AS RESTATED, SEE NOTE 20)
---------------------------
DECEMBER 31
---------------------------
2001 2002
------------ -------------
(Dollars in thousands)
Current liabilities:
Accounts payable ....................................................... $ 10,542 $ 9,687
Joint interest oil and gas production payable .......................... 3,596 2,432
Accrued interest ....................................................... 6,013 6,009
Other accrued expenses ................................................. 1,116 1,162
Hedge liability ........................................................ 658 -
Current maturities of long-term debt ................................... 415 63,500
------------ -------------
Total current liabilities ............................................ 22,340 82,790
Long-term debt ............................................................ 285,184 236,943
Deferred income taxes ..................................................... 20,621 -
Future site restoration ................................................... 4,056 3,946
Commitments and contingencies
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized 200,000,000 shares;
issued 30,145,280 at December 31, 2001 and 2002 ...................... 301 301
Additional paid-in capital ............................................. 136,830 136,830
Receivables from stock sale ............................................ (97) (97)
Accumulated deficit .................................................... (151,094) (269,621)
Treasury stock, at cost, 165,883 shares ................................ (964) (964)
Accumulated other comprehensive income (loss) .......................... (13,561) (8,703)
------------ -------------
Total stockholders' equity (deficit) ..................................... (28,585) (142,254)
------------ -------------
Total liabilities and stockholders' equity (deficit) ................... $ 303,616 $ 181,425
============ =============
</Table>
See accompanying Notes to Consolidated Financial Statements
F-4
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<Table>
<Caption>
(AS RESTATED, SEE NOTE 20)
------------------------------------------
YEAR ENDED DECEMBER 31
------------------------------------------
2000 2001 2002
------------------------------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 72,973 $ 73,201 $ 50,862
Gas processing revenues ................................. 2,717 2,438 2,420
Rig revenues ............................................ 505 756 635
Other ................................................... 405 848 403
------------- ------------ -------------
76,600 77,243 54,320
Operating costs and expenses:
Lease operating and production taxes .................... 18,783 18,616 15,240
Depreciation, depletion, and amortization ............... 35,857 32,484 26,539
Proved property impairment .............................. - 2,638 115,993
Rig operations .......................................... 717 702 567
General and administrative .............................. 6,533 6,445 6,884
General and administrative (Stock-based compensation) ... 2,767 (2,767) -
------------- ------------ -------------
64,657 58,118 165,223
------------- ------------ -------------
Operating income (loss) .................................... 11,943 19,125 (110,903)
Other (income) expense:
Interest income ......................................... (530) (78) (92)
Amortization of deferred financing fees ................. 2,091 2,268 2,095
Interest expense ........................................ 31,140 31,523 34,150
Financing costs ......................................... - - 967
(Gain) loss on sale of equity investment ................ (33,983) 845 -
Gain on debt extinguishment ............................. (1,773) - -
Other ................................................... 1,563 207 201
------------- ------------ -------------
(1,492) 34,765 37,321
------------- ------------ -------------
Income (loss) before income tax ............................ 13,435 (15,640) (148,224)
Income tax expense (benefit):
Current ................................................. (1,233) 505 -
Deferred ................................................ 4,938 1,897 (29,697)
Minority interest in income of foreign subsidiary (2001
prior to purchase) ...................................... 1,281 1,676 -
------------- ------------ -------------
Net income (loss) .......................................... $ 8,449 $ (19,718) $ (118,527)
============= ============ =============
Net income (loss) per common share - basic ................. $ 0.37 $ (0.76) $ (3.95)
============= ============ =============
Net income (loss) per common share - diluted .............. $ 0.26 $ (0.76) $ (3.95)
============= ============ =============
</Table>
See Accompanying Notes to Consolidated Financial Statements
F-5
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands except share amounts)
<Table>
<Caption>
COMMON STOCK TREASURY STOCK
---------------------------- ------------------------------
SHARES AMOUNT SHARES AMOUNT
----------- ------------ ------------- ------------
Balance at January 1, 2000 ........... 22,747,099 $ 227 152,083 $ (1,071)
Comprehensive income (loss):
Net income ........................ - - - -
Other comprehensive income:
Foreign currency translation
adjustment ................. - - - -
Comprehensive income (loss)
Stock-based compensation expense .. - - - -
Issuance of common stock and
warrants for compensation ....... 12,753 - (25,000) 185
Purchase of treasury stock ........ - - 38,800 (78)
----------- ------------ ------------- ------------
Balance at December 31, 2000 ......... 22,759,852 $ 227 165,883 $ (964)
Comprehensive income (loss):
Net loss .......................... - - - -
Other comprehensive income:
Hedge loss ................... - - - -
Foreign currency translation
adjustment ................. - - - -
Comprehensive income (loss)
Stock-based compensation expense .. - - - -
Issuance of common stock for
contingent value rights ......... 3,386,488 34 - -
Issuance of common stock and
stock options for acquisition
of minority interest in Old
Grey Wolf Exploration, Inc. ..... 3,990,565 40 - -
Stock options exercised ........... 8,375 - - -
----------- ------------ ------------- ------------
Balance at December 31, 2001 ......... 30,145,280 $ 301 165,883 $ (964)
----------- ------------ ------------- ------------
<Caption>
ACCUMULATED
ADDITIONAL OTHER RECEIVABLES
PAID-IN ACCUMULATED COMPREHENSIVE FROM
CAPITAL DEFICIT INCOME (LOSS) STOCK SALE TOTAL
-------------------------------------------------------------------------------
Balance at January 1, 2000 $ 127,562 $ (139,825) $ 3,602 $ (97) $ (9,602)
Comprehensive income (loss):
Net income ........................ - 8,449 - - 8,449
Other comprehensive income:
Foreign currency translation
adjustment ................. - - (8,401) - (8,401)
-------------
Comprehensive income (loss) 48
Stock-based compensation expense .. 2,767 - - - 2,767
Issuance of common stock and
warrants for compensation ....... 80 - - - 265
Purchase of treasury stock ........ - - - - (78)
------------- -------------- -------------- ------------- -------------
Balance at December 31, 2000 ......... $ 130,409 $ (131,376) $ (4,799) $ (97) $ (6,600)
Comprehensive income (loss):
Net loss .......................... - (19,718) - (19,718)
Other comprehensive income:
Hedge loss ................... - - (566) - (566)
Foreign currency translation
adjustment ................. - - (8,196) - (8,196)
-------------
Comprehensive income (loss) (28,480)
Stock-based compensation expense .. (2,767) - - - (2,767)
Issuance of common stock for
contingent value rights ......... (34) - - - -
Issuance of common stock and
stock options for acquisition
of minority interest in Old
Grey Wolf Exploration, Inc. ..... 9,206 - - - 9,246
Stock options exercised ........... 16 - - - 16
------------- -------------- -------------- ------------- -------------
Balance at December 31, 2001 ......... $ 136,830 $ (151,094) $ (13,561) $ (97) $ (28,585)
------------- -------------- -------------- ------------- -------------
</Table>
(continued)
F-6
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)(continued)
(In thousands except share amounts)
<Table>
<Caption>
COMMON STOCK TREASURY STOCK
----------------------------- -----------------------------
SHARES AMOUNT SHARES AMOUNT
------------- ------------- ------------- -------------
Balance at December 31, 2001 ........... 30,145,280 $ 301 165,883 $ (964)
Comprehensive income (loss):
Net loss ............................ - - - -
Other comprehensive income:
Hedge income .................... - - - -
Foreign currency
translation adjustment ........ - - - -
------------- ------------- ------------- -------------
Comprehensive income (loss)
Balance at December 31, 2002 ........... 30,145,280 $ 301 165,883 $ (964)
============= ============= ============= =============
<Caption>
ACCUMULATED
ADDITIONAL OTHER RECEIVABLES
PAID-IN ACCUMULATED COMPREHENSIVE FROM
CAPITAL DEFICIT INCOME (LOSS) STOCK SALE TOTAL
------------- -------------- ------------- ------------- ------------
Balance at December 31, 2001 ........... $ 136,830 $ (151,094) $ (13,561) $ (97) $ (28,585)
Comprehensive income (loss):
Net loss ............................ - (118,527) - - (118,527)
Other comprehensive income:
Hedge income .................... - - 566 - 566
Foreign currency
translation adjustment ........ - - 4,292 - 4,292
------------
Comprehensive income (loss) (113,669)
------------- -------------- ------------- ------------- ------------
Balance at December 31, 2002 ........... $ 136,830 $ (269,621) $ (8,703) $ (97) $ (142,254)
============= ============== ============= ============= ============
</Table>
See accompanying Notes to Consolidated Financial Statements.
F-7
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
(AS RESTATED, SEE NOTE 20)
--------------------------------------
YEAR ENDED DECEMBER 31
--------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands)
OPERATING ACTIVITIES
Net income (loss) ...................................................... $ 8,449 $ (19,718) $ (118,527)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Minority interest in income of foreign subsidiary ................. 1,281 1,676 -
Gain on extinguishment of debt .................................... (1,773) - -
(Gain) loss on sale of equity investment .......................... (33,983) 845 -
Depreciation, depletion, and amortization ........................ 35,857 32,484 26,539
Proved property impairment ........................................ - 2,638 115,993
Deferred income tax expense ....................................... 4,938 1,897 (29,697)
Amortization of deferred financing fees ........................... 2,091 2,268 2,095
Stock-based compensation .......................................... 2,767 (2,767) -
Issuance of common stock and warrants for compensation ............ 265 - -
Changes in operating assets and liabilities:
Accounts receivable ............................................ (7,036) 12,693 (2,247)
Equipment inventory ............................................ (538) (76) 201
Other .......................................................... (1,839) (106) 126
Accounts payable ............................................... 11,318 (14,848) (2,775)
Accrued expenses ............................................... (425) (723) (44)
---------- ---------- ----------
Net cash provided by (used) in operations .............................. 21,372 16,263 (8,336)
INVESTING ACTIVITIES
Capital expenditures, including purchases and development of properties (74,412) (57,056) (38,912)
Proceeds from sale of oil and gas properties ........................... 21,157 28,938 33,876
Acquisition of minority interest ....................................... - (2,679) -
Proceeds from sale of equity investment ................................ 34,482 - -
---------- ---------- ----------
Net cash used in investing activities .................................. (18,773) (30,797) (5,036)
</Table>
F-8
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
<Table>
<Caption>
YEAR ENDED DECEMBER 31
------------------------------------------------------
2000 2001 2002
--------------- -------------- -------------
(In thousands)
FINANCING ACTIVITIES
Purchase of treasury stock, net ............ $ (78) $ - $ -
Proceeds from issuance of common stock...... - 16 -
Proceeds from long-term borrowings ......... 6,400 29,995 20,551
Payments on long-term borrowings ........... (10,163) (9,326) (8,176)
Deferred financing fees .................... 23 - (1,539)
--------------- -------------- -------------
Net cash (used) provided by financing
activities............................... (3,818) 20,685 10,836
--------------- -------------- -------------
Increase (decrease) in cash ................ (1,219) 6,151 (2,536)
--------------- -------------- -------------
Effect of exchange rate changes on cash..... (576) (550) (187)
--------------- -------------- -------------
Increase (decrease) in cash ................ (1,795) 5,601 (2,723)
--------------- -------------- -------------
Cash at beginning of year .................. 3,799 2,004 7,605
--------------- -------------- -------------
Cash at end of year......................... $ 2,004 $ 7,605 $ 4,882
=============== ============== =============
SUPPLEMENTAL DISCLOSURES
Supplemental disclosures of cash flow
information:
Interest paid ......................... $ 33,004 $ 31,752 $ 34,154
=============== ============== =============
Taxes paid............................. $ - $ 505 $ -
=============== ============== =============
Supplemental schedule of noncash investing
and financing activities:
In May 2001 the Company issued 3,386,488 shares of common
stock upon the expiration of the CVRs issued in connection
with the December 1999 exchange. See Note 6.
In September 2001 the Company issued 3,990,565 shares of
common stock and options and paid $2,679,000 million in cash
in connection with the acquisition of the minority interest
in Old Grey Wolf. See Note 4.
Decrease in oil and gas properties and other assets....... $ (2,925)
=============
Decrease in deferred income tax liability................. $ 1,091
=============
Increase in stockholders equity........................... $ (9,246)
=============
Decrease in minority interest in foreign subsidiary....... $ 13,759
=============
</Table>
See accompanying Notes to Consolidated Financial Statements.
F-9
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000, 2001 and 2002
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an
independent energy company engaged in the exploration for and the acquisition,
development, and production of crude oil and natural gas primarily along the
Texas Gulf Coast, in the Permian Basin of western Texas and in western Canada.
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries. All intercompany accounts and transactions have
been eliminated in consolidation.
The consolidated financial statements include the accounts of the Company,
and its wholly owned foreign subsidiaries Canadian Abraxas Petroleum Limited
("Canadian Abraxas") and Grey Wolf Exploration, Inc. ("Grey Wolf"). Minority
interest represents the minority shareholders' proportionate share of the equity
and income of Grey Wolf prior to the Company's acquisition of the remaining
interest in September 2001.
In January 2003, the Company sold all of the common stock of Canadian
Abraxas and Grey Wolf. Certain oil and gas properties were retained and
transferred into a new wholly owned subsidiary that retained the name Grey Wolf
Exploration, Inc. ("New Grey Wolf").
USE OF ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Management believes that it is reasonably possible that estimates of
proved crude oil and natural gas revenues could significantly change in the
future.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially expose the Company to credit
risk consist principally of trade receivables, interest rate and crude oil and
natural gas price swap agreements. Accounts receivable are generally from
companies with significant oil and gas marketing activities. The Company
performs ongoing credit evaluations and, generally, requires no collateral from
its customers.
EQUIPMENT INVENTORY
Equipment inventory principally consists of casing, tubing, and
compression equipment and is carried at the lower of cost or market.
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for crude oil and
natural gas properties. Under this method, all direct costs and certain indirect
costs associated with acquisition of properties and successful as well as
unsuccessful exploration and development activities are capitalized.
Depreciation, depletion, and amortization of capitalized crude oil and natural
gas properties and estimated future development costs, excluding unproved
properties, are based on the unit-of-production method based on proved reserves.
Net capitalized costs of crude oil and natural gas properties, less related
deferred taxes, are limited, by country, to the lower of unamortized cost or the
cost ceiling, defined as the sum of the present value of estimated future net
revenues from proved reserves based on unescalated prices discounted at 10
percent, 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
F-10
<Page>
being amortized, if any, less related income taxes. Excess costs are charged to
proved property impairment expense. No gain or loss is recognized upon sale or
disposition of crude oil and natural gas properties, except in unusual
circumstances.
Unproved properties represent costs associated with properties on which
the Company is performing exploration activities or intends to commence such
activities. These costs are reviewed periodically for possible impairments or
reduction in value based on geological and geophysical data. If a reduction in
value has occurred, costs being amortized are increased. The Company believes
that the unproved properties will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time. During
2000, 2001 and 2002 the Company capitalized $589,000, $164,000 and $152,000 of
interest expense respectively, based on the cost of major development projects
in progress.
OTHER PROPERTY AND EQUIPMENT
Other property and equipment are recorded on the basis of cost.
Depreciation of other property and equipment is provided over the estimated
useful lives using the straight-line method. Major renewals and betterments are
recorded as additions to the property and equipment accounts. Repairs that do
not improve or extend the useful lives of assets are expensed.
HEDGING
The Company periodically enters into agreements to hedge the risk of
future crude oil and natural gas price fluctuations. Such agreements, primarily
in the form of price swaps, may either fix or support crude oil and natural gas
prices or limit the impact of price fluctuations with respect to the Company's
sale of crude oil and natural gas. Gains and losses on such hedging activities
are recognized in oil and gas production revenues when hedged production is
sold. The net cash flows related to any recognized gains or losses associated
with these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the contract
is delivered.
Statement of Financial Accounting Standards, ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," is effective for
the Company on January 1, 2001. SFAS 133, as amended and interpreted,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. All derivatives, whether designated in hedging relationships
or not, will be required to be recorded on the balance sheet at fair value. If
the derivative is designated a fair-value hedge, the changes in the fair value
of the derivative and the hedged item will be recognized in earnings. If the
derivative is designated a cash-flow hedge, changes in the fair value of the
derivative will be recorded in other comprehensive income (OCI) and will be
recognized in the income statement when the hedged item affects earnings. SFAS
133 defines new requirements for designation and documentation of hedging
relationships as well as ongoing effectiveness assessments in order to use hedge
accounting. For a derivative that does not qualify as a hedge, changes in fair
value will be recognized in earnings.
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 March 1999, the Company amended the exercise price to $2.06 on all
options with an existing exercise price greater than $2.06. See Note 7. The
Company recognized approximately $2.8 million in expense during 2000 and a
credit of $2.8 million during 2001 as General and Administrative (Stock-based
compensation). The credit for the year ended December 31, 2001 was due to a
decline in the Company's common stock price.
Pro forma information regarding net income (loss) and earnings (loss)
per share is required by SFAS 123, "Accounting for Stock-Based Compensation,"
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 that SFAS. The fair value for these
options was estimated at the date of grant using a Black-Scholes option pricing
model with the following
F-11
<Page>
weighted-average assumptions for 2000, 2001 and 2002, risk-free interest rates
of 6.25%, 3.50% and 1.5%, respectively; dividend yields of -0-%; volatility
factors of the expected market price of the Company's common stock of .916, .35
and .35, respectively; 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.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows:
<Table>
<Caption>
Year Ended December 31
------------------------------------------
2000 2001 2002
------------ ------------ ------------
Net income as reported $ 8,449 $ (19,718) $ (118,527)
Add: Stock-based employee compensation expense included in
reported net income, net of related tax effects 2,767 (2,767) -
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects (1,127) (1,284) (670)
------------ ------------ ------------
Pro forma net income (loss) $ 10,089 $ (23,769) $ (119,197)
============ ============ ============
Earnings (loss) per share:
Basic - as reported $ 0.37 $ (0.76) $ (3.95)
============ ============ ============
Basic - pro forma $ 0.45 $ (0.92) $ (3.98)
============ ============ ============
Diluted - as reported $ 0.26 $ (0.76) $ (3.95)
============ ============ ============
Diluted - pro forma $ 0.31 $ (0.92) $ (3.98)
============ ============ ============
</Table>
FOREIGN CURRENCY TRANSLATION
The functional currency for Canadian Abraxas and Grey Wolf (Old and New)
is the Canadian dollar ($CDN). The Company translates the functional currency
into U.S. dollars ($US) based on the current exchange rate at the end of the
period for the balance sheet and a weighted average rate for the period on the
statement of operations. Translation adjustments are reflected as Accumulated
Other Comprehensive Income (Loss) in Stockholders' Equity (Deficit). See Note 2
for Canadian subsidiaries sold in 2003. A portion of the translation account
will be eliminated at the closing of the sale in 2003.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company includes fair value information in the notes to consolidated
financial statements when the fair value of its financial instruments is
materially different from the book value. The Company assumes the book value of
those financial instruments that are classified as current approximates fair
value because of the short maturity of these instruments. For noncurrent
financial instruments, the Company uses quoted market prices or, to the extent
that there are no available quoted market prices, market prices for similar
instruments.
RESTORATION, REMOVAL AND ENVIRONMENTAL LIABILITIES
The estimated costs of restoration and removal of facilities are accrued
on a straight-line basis over the life of the property. The estimated future
costs for known environmental remediation requirements are accrued when it is
probable that a liability has been incurred and the amount of remediation costs
can be reasonably estimated. These amounts are the undiscounted, future
estimated costs under existing regulatory requirements and using existing
technology.
F-12
<Page>
REVENUE RECOGNITION
The Company recognizes crude oil and natural gas revenue from its
interest in producing wells as crude oil and natural gas is sold from those
wells, net of royalties. Revenue from the processing of natural gas is
recognized in the period the service is performed. The Company utilizes the
sales method to account for gas production volume imbalances. Under this method,
income is recorded based on the Company's net revenue interest in production
taken for delivery. The Company had no material gas imbalances.
DEFERRED FINANCING FEES
Deferred financing fees are being amortized on a level yield basis over
the term of the related debt arrangements.
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 bases 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.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the purchase method of
accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. Intangible assets with a determinable
useful life will continue to be amortized over that period. The amortization
provisions apply to goodwill and intangible assets acquired after June 30, 2001.
SFAS No. 141 and 142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did not change or
reclassify contractual mineral rights included in oil and gas properties on the
balance sheet upon adoption of SFAS No. 142. The Company believes the treatment
of such mineral rights as tangible assets under the full cost method of
accounting for crude oil and natural gas properties is appropriate. An issue has
arisen regarding whether contractual mineral rights should be classified as
intangible rather that tangible assets. If it is determined that
reclassification is necessary, the Company's oil and gas properties would be
reduced by $868,000 and $3.1 million and intangible assets would have increased
by a like amount at December 31, 2001 and 2002, respectively, representing cost
incurred from the effective date of June 30, 2001. The provisions of SFAS No.
141 and 142 impact only the balance sheet and associated footnote disclosure,
and reclassifications necessary would not impact the Company's cash flows or
results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 is effective for us January 1,
2003. SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortize these costs as a component of our depletion
expense.
We have completed our assessment of SFAS No. 143 and based on our
estimates, we do not expect the statement to have a material effect on our
financial position, results of operations and cash flows for future periods. At
January 1, 2003 , we estimate that the present value of our future Asset
Retirement Obligation ("ARO") for natural gas and oil property and related
equipment is approximately $657,000. We estimate that the cumulative effect to
the adoption of SFAS No. 143 and the change in the accounting principal will be
a loss of $285,000, which will be recorded in the first quarter of 2003. The
impact on each of the prior periods was not material.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Asset." Effective January 1, 2002, the
Company adopted SFAS No. 144. SFAS No. 144 retains the requirement to recognize
an impairment loss only where the carrying value of a long-lived asset is not
recoverable from its undiscounted cash flows and to measure such loss as the
difference between the carrying amount and fair value of the asset. SFAS No.
144, among other things,
F-13
<Page>
changes the criteria that have to be met to classify an asset as held-for-sale
and requires that operating losses from discontinued operations be recognized in
the period that the losses are incurred rather than as of the measurement date.
This new standard had no impact on the Company's consolidated financial
statements for the year ended December 31, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4,
44, and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS
No. 145 clarifies guidance related to the reporting of gains and losses from
extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS No. 145 also amends
other existing pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed conditions. The
provisions relating to the reporting of gains and losses from extinguishment of
debt become effective for us beginning January 1, 2003. All other provisions of
this standard were effective for the Company as of May 15, 2002 and did not have
an impact on the Company's financial condition or results of operations. Upon
issuance of our restated financial statements, see Note 20, the Company has
reclassified the gain on the early extinguishment of debt in 2000 from an
extraordinary item to other income. This reclassification did not affect net
income for the year ended December 31, 2000.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. SFAS
No. 146 is effective for us beginning January 1, 2003. The Company is currently
evaluating the impact the standard will have on its results of operations and
financial condition.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-based Compensation--Transition and Disclosure, an amendment of FASB
Statement No. 123," which amends SFAS No. 123 to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. It also amends the disclosure provisions
of SFAS No. 123 to require prominent disclosure in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. The
provisions of SFAS No. 148 are effective for annual financial statements for
fiscal years ending after December 15, 2002, and for financial reports
containing condensed financial statements for interim periods beginning after
December 15, 2002. The Company will continue to use APB No. 25 to account for
stock based compensation, while providing the disclosures required by SFAS 123
as amended by SFAS 148.
RECLASSIFICATIONS
Certain prior years balances have been reclassified for comparative
purposes.
2. 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
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
such notes tendered in the exchange offer, tendering note holders received:
- cash in the amount of $264;
- an 11 1/2% Secured Note due 2007, Series A, ("New Notes") with a
principal amount equal to $610; and
- 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately $190.2
million of the Second Lien Notes and $801,000 of the Old Notes outstanding - see
Note 3. 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, for approximately $11.5
million ($11.1 million in principal and $0.4 million in interest). The
indentures for the Second Lien Notes and Old Notes have been duly discharged. In
connection with the exchange offer, Abraxas made cash payments of approximately
$47.5 million and issued approximately $109.7 million in principal amount of New
Notes and 5,642,699 shares of Abraxas common stock. Fees and expenses incurred
in connection with the exchange offer were approximately $3.8 million ($967,000
was charged to expense in 2002 and is included in financing costs in the
accompanying statement of operations). The balance will be charged to expense in
2003 as the cost are incurred.
F-14
<Page>
NEW NOTES. The new notes will 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 the Company fails, or
are not permitted pursuant to the new senior secured credit agreement or the
intercreditor agreement between the trustee under the indenture for the New
Notes and the lenders under the new senior secured credit agreement, to make
such cash interest payments in full, the Company will pay such unpaid interest
in kind by the issuance of additional notes with a principal amount equal to the
amount of accrued and unpaid cash interest on the notes plus an additional 1%
accrued interest for the applicable period. Upon an event of default, interest
will accrue at an annual rate of 16.5%. The New Notes are guaranteed by all of
Abraxas' current subsidiaries, Sandia Oil & Gas Corp., Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation, Eastside Coal
Company, Inc., and New Grey Wolf, and will be guaranteed by all of Abraxas'
future subsidiaries. The New Notes are secured by a second lien or charge on all
of the Company's current and future assets, including, but not limited to, its
crude oil and natural gas properties.
REDEMPTION OF FIRST LIEN NOTES. On January 24, 2003, the Company
completed the redemption of 100% of our outstanding 12?% Senior Secured Notes,
Series A, ("First Lien Notes") - see Note 4, with approximately $66.4 million of
the proceeds from the sale of Canadian Abraxas and Old Grey Wolf. Prior to the
redemption, the Company had $63.5 million of its First Lien Notes outstanding.
Under the terms of the indenture for the First Lien Notes the Company had the
right to redeem the First Lien Notes at 100% of the outstanding principal amount
of the notes, plus accrued and unpaid interest to the date of redemption, and to
discharge the indenture upon call of the First Lien Notes for redemption and
deposit of the redemption funds with the trustee. The Company exercised these
rights on January 23, 2003 and upon the discharge of the indenture, the trustee
released the collateral securing the Company's obligations under the First Lien
Notes.
NEW SENIOR SECURED CREDIT AGREEMENT. Contemporaneously with the closing
of the exchange offer and the sale of Canadian Abraxas and Old Grey Wolf, on
January 23, 2003, Abraxas entered into a new senior secured credit agreement
providing a term loan facility of $4.2 million and a revolving credit facility
with a maximum borrowing base of up to $50 million. 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 secured 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 secured 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 capitalized and added to the principal amount of the term
loan facility until maturity.
REVOLVING CREDIT FACILITY. Lenders under the new senior secured 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 $49.9 million, subject to adjustments based on
periodic calculations and mandatory prepayments under the senior secured 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. At January 23, 2003, the Company has borrowed $42.5 million under the
revolving credit facility, all of which was used to make cash payments in
connection with the financial restructuring. The Company plans to use the
remaining borrowing availability under the new senior secured credit agreement
to fund its operations, including capital expenditures.
COVENANTS. Under the new senior secured 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 secured credit agreement), minimum ratios of
consolidated EBITDA to cash interest expense and a limitation on annual capital
expenditures. In addition, at the end of each fiscal quarter, if the aggregate
amount of our cash and cash equivalents exceeds $2.0 million, the Company is
required to repay the loans under the new senior secured credit agreement in an
amount equal to such excess. The new senior secured credit agreement also
requires the Company 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 secured credit agreement.
In addition to the foregoing and other customary covenants, the new
senior secured credit agreement contains a number of covenants that, among other
things, restrict the Company's ability to:
- incur additional indebtedness;
- create or permit to be created any liens on any of our
properties;
F-15
<Page>
- enter into any change of control transactions;
- dispose of our assets;
- change our name or the nature of our business;
- make any guarantees with respect to the obligations of third
parties;
- enter into any forward sales contracts;
- make any payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
- make investments or incur liabilities.
GUARANTEES. The obligations of Abraxas under the new senior secured
credit agreement are guaranteed by Sandia Oil & Gas, Sandia Operating,
Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal.
Obligations under the new senior secured credit agreement are secured by a first
lien security interest in substantially all of Abraxas' and 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.
SALE OF STOCK OF CANADIAN ABRAXAS AND OLD GREY WOLF. Contemporaneously
with the closing of the exchange offer, on January 23, 2003, Abraxas completed
the sale to a wholly owned subsidiary of PrimeWest Energy Inc. of all of the
outstanding capital stock of Canadian Abraxas and Old Grey Wolf for
approximately $138 million before net adjustments of $3.4 million. The aggregate
sales price for the shares was as follows:
<Table>
<Caption>
Number of Shares Sales Price
---------------- -------------
Canadian Abraxas 5,751 common shares $ 68 million
Old Grey Wolf 12,804,628 common shares $ 70 million
-------------
Total Sales Price: $ 138 million
=============
</Table>
After sales price adjustments and related costs and expenses of
approximately $5.9 million were made, the sales price realized for the sale of
Canadian Abraxas and Old Grey Wolf was $132.1 million. Upon consummation of the
sale, Old Grey Wolf repaid the then current outstanding indebtedness under its
credit agreement with Mirant Canada Energy Capital, Ltd. ("Grey Wolf Facility")
in the amount of $46.3 million - see Note 3, which reduced the net proceeds from
the sale by a corresponding amount. The net cash proceeds from the sale were
$85.8 million, all of which has been utilized in connection with the financial
restructuring. The Company estimates a gain on the sale of Canadian Abraxas and
Old Grey Wolf of approximately $69 million at the time of closing in 2003.
Under the terms of the agreement with PrimeWest, Abraxas has retained
certain oil and gas properties formerly held by Canadian Abraxas and Old Grey
Wolf, including all of Canadian Abraxas' and Old Grey Wolf's undeveloped acreage
existing at the time of the sale, which includes all of our interests in the
Ladyfern area. These assets have been contributed to New Grey Wolf. Portions of
this undeveloped acreage will be developed by PrimeWest and New Grey Wolf under
a farmout arrangement. Under the farmout arrangements, PrimeWest has agreed to
participate in the development of certain lands of New Grey Wolf in the Caroline
and Pouce Coupe areas of Alberta. PrimeWest has the right to earn a 60% interest
in certain wells if it bears 100% of the expense of drilling such wells. In
addition, New Grey Wolf and PrimeWest will have an area of mutual interest in
respect of the lands surrounding the Caroline area where each party will be
entitled to participate in the acquisition of the other, with New Grey Wolf
participating with a 40% interest and PrimeWest participating with a 60%
interest.
The following presents the summarized results of operations for the years
ended December 31, 2000, 2001, and 2002, for the Canadian properties which were
not retained after the transaction in January 2003.
F-16
<Page>
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
2000 2001 2002
------------ ------------ ------------
Total revenue.......................................... $ 43,714 $ 41,468 $ 32,013
============ ============ ============
Loss from operations before income tax ................ (1,707) (102) (87,378)
Income tax expense (benefit)........................... 272 1,897 (29,697)
Minority interest in income............................ (1,281) (1,676) -
------------ ------------ ------------
Loss from operations................................... $ (3,260) $ (3,675) $ (57,681)
============ ============ ============
</Table>
Assets and liabilities related to the Canadian properties which were not
retained after the January 2003 transaction:
<Table>
<Caption>
December 31,
2002
------------
Assets:
Cash................................................... $ 4,325
Accounts receivable.................................... 4,016
Net property and equipment............................. 54,468
Other.................................................. 11,438
------------
$ 74,247
============
Liabilities:
Accounts payable and accrued liabilities............... $ 7,320
Long-tern debt......................................... 45,964
Other.................................................. 3,413
------------
$ 56,697
============
</Table>
Included in the loss from operations shown above are interest expense of
$8.3 million, $7.6 million, and $9.5 million, and general and administrative
expense of $1.7 million, $1.5 million, and $1.7 million for the years ended
December 31, 2000, 2001 and 2002, respectively. The interest expense
represents the amounts relating to an Old Grey Wolf senior credit facility
which was repaid in conjunction with the transactions described above and
the amounts related to the balance of certain noted (approximately $52.6
million) which had historically been reflected by Canadian Abraxas. At the
time of the subsidiary sale, the balance of the outstanding notes were
transferred to the parent and subject to the financial restructuring
described in Note 3. The general and administrative expense of the Canadian
subsidiaries above were determined by considering the on-going general and
administrative cost associated with the Canadian properties retained by the
Company.
3. LONG-TERM DEBT
As described in Note 2, the First Lien Notes were redeemed in January
2003. The Old Notes and the Second Lien Notes were either redeemed or exchanged
for cash, common stock and New Notes in January 2003. Additionally, the 9.5%
Mirant Canada Energy Capital, Ltd. credit facility, with a balance outstanding
at December 31, 2002 of $45.9 million, was repaid in connection with the sale of
the common stock of Old Grey Wolf in January 2003.
The following is a brief description of the Company's debt as of
December 31, 2002. The pro forma unaudited information reflects the impact of
the financial restructuring transactions - see Note 2.
Long-term debt consists of the following:
F-17
<Page>
<Table>
<Caption>
PRO FORMA
DECEMBER 31,
2002 (a)
DECEMBER 31 (UNAUDITED)
------------------------------------------
2001 2002
------------ ------------ ------------
(In thousands)
11.5% Senior Notes due 2004 ("Old Notes") ................... $ 801 $ 801 $ -
12.875% Senior Secured Notes due 2003 ("First Lien Notes") .. 63,500 63,500 -
11.5% Second Lien Notes due 2004 ("Second Lien Notes")....... 190,178 190,178 -
9.5% Senior Credit Facility ("Grey Wolf Facility") providing
for borrowings up to approximately US $96 million
(CDN $150 million). Secured by the assets of Old Grey
Wolf and non-recourse to Abraxas........................ 22,944 45,964 -
11.5% Secured Notes due 2007 ("New Notes") - January 2003.... - - 128,600
New Senior Secured Credit Agreement - January 2003........... - - 46,700
Production Payment ......................................... 8,176 - -
------------ ------------ ------------
285,599 300,443 175,300
Less current maturities ..................................... 415 63,500 -
------------ ------------ ------------
$ 285,184 $ 236,943 $ 175,300
============ ============ ============
</Table>
(a) After transactions described in Note 2, for financial reporting purposes,
the New Notes will be reflected at the carrying value of the Second Lien Notes
and Old Notes prior to the exchange of $191.0 million, net of the cash offered
in the exchange of $47.5 million and net of the fair market value related to
equity of $3.8 million offered in the exchange. In conjunction with the
financial restructuring transaction, Abraxas paid cash of $11.5 million ($11.1
million in principal and $0.4 million in interest) to redeem certain of the
outstanding old debt and accrued interest. The result of all of these items will
be a remaining carrying value of the New Notes of $128.6 million. The face
amount of the New Notes is $109.7 million. See Note 2 for terms and conditions
of the New Notes and the New Senior Secured Credit Agreement.
OLD NOTES. Interest on the Old Notes is payable semi-annually in arrears
on May 1 and November 1 of each year at the rate of 11.5% per annum. The Old
Notes are redeemable, in whole or in part, at the option of the Company.
FIRST LIEN NOTES. Interest on the First Lien Notes is payable
semi-annually in arrears on March 15 and September 15 of each year at the rate
of 12.875% per annum.
SECOND LIEN NOTES. Interest on the Second Lien Notes is payable
semi-annually in arrears on May 1 and November 1, commencing May 1, 2000.
PRODUCTION PAYMENT
In October 1999, the Company entered into a non-recourse dollar denominated
production payment agreement (the "Production Payment") with a third party. The
Production Payment had an aggregate total availability of up to $50 million at
15% interest. The Production Payment related to a portion of the production from
several natural gas wells in South Texas. The Company reacquired the Production
Payment in June 2002, for approximately $6.8 million.
EARLY DEBT EXTINGUISHMENT
In June 2000, the Company retired $3.5 million of the Old Notes and $3.6
million of the Second Lien Notes at a discount of $1.8 million initially
reflected as a gain. Upon reissuance of our financial statements, see Note 20,
the Company has reclassified this gain from an extraordinary item to other
income. This reclassification did not affect net income for the year ended
December 31, 2000.
4. ACQUISITIONS AND DIVESTITURES
ABRAXAS WAMSUTTER L.P. DIVESTITURE
In November 1998, the Company sold its interest in certain Wyoming
properties to Abraxas Wamsutter L.P., a Texas limited partnership (the
"Partnership"), for approximately $58.6 million and a minority equity ownership
in the Partnership. Wamsutter Holdings, Inc. ("Wamsutter") initially owned a one
percent interest and acted as general partner of the Partnership. The investment
in the Partnership was accounted for by the equity method. After certain payback
requirements were satisfied, the Company's interest would increase to 35%
initially and could increase to as high as 65%. The Company also received a
management fee and reimbursement of certain overhead costs from the Partnership
which amounted to $112,700 for the year ended December 31, 2000.
In March 2000, the Partnership sold all of its interest in its crude oil
and natural gas properties to a third party. Prior to the sale of these
properties, effective January 1, 2000, the Company's equity investee share of
oil and gas property cost, results
F-18
<Page>
of operations and amortization were not material to consolidated operations or
financial position. As a result of the sale, the Company received approximately
$34 million, which represented a proportional interest in the Partnership's
proved properties. See Note 10 regarding a litigation provision in 2001 of
$845,000 related to ad valorem taxes.
ACQUISITION OF MINORITY INTEREST IN OLD GREY WOLF
In September 2001, the Company completed a tender offer for the minority
interest in Old Grey Wolf, acquiring the approximately 52% of capital stock that
was not previously owned by the Company. The Company issued 3,990,565 common
shares and 588,916 stock options, valued together at approximately $9.2 million.
Additionally, the Company incurred direct costs of approximately $2.7 million
related to the acquisition. The elimination of the minority interest through an
acquisition at a purchase price less than Old Grey Wolf's book value in the
Company's consolidated financial statements had the effect of reducing the
property and other assets balances by $2.9 million and deferred income taxes by
$1.1 million.
The Company sold all of the common stock in Old Grey Wolf in January
2003 - see Note 2.
5. PROPERTY AND EQUIPMENT
The major components of property and equipment, at cost, are as follows:
<Table>
<Caption>
DECEMBER 31
ESTIMATED ---------------------------
USEFUL LIFE 2001 2002
--------------- ----------- ------------
Years (In thousands)
Land, buildings, and improvements .............. 15 $ 318 $ 331
Crude oil and natural gas properties ........... - 496,724 529,047
Natural Gas Processing.......................... 18 63,964 38,735
Equipment and other ............................ 7 3,350 5,123
----------- ------------
$ 564,356 $ 573,236
=========== ============
</Table>
6. STOCKHOLDERS' EQUITY
COMMON STOCK
See Note 2 - Recent Events for common stock issued in January 2003 as
part of an exchange offer.
In 1994, the Board of Directors adopted a Stockholders' Rights Plan and
declared a dividend of one Common Stock Purchase Right ("Rights") for each share
of common stock. The Rights are not initially exercisable. Subject to the Board
of Directors' option to extend the period, the Rights will become exercisable
and will detach from the common stock ten days after any person has become a
beneficial owner of 20% or more of the common stock of the Company or has made a
tender offer or Exchange Offer (other than certain qualifying offers) for 20% or
more of the common stock of the Company.
Once the Rights become exercisable, each Right entitles the holder,
other than the acquiring person, to purchase for $40 a number of shares of the
Company's common stock having a market value of two times the purchase price.
The Company may redeem the Rights at any time for $.01 per Right prior to a
specified period of time after a tender or Exchange Offer. The Rights will
expire in November 2004, unless earlier exchanged or redeemed.
CONTINGENT VALUE RIGHTS ("CVRS")
As part of an exchange offer consummated by the Company in December
1999, Abraxas issued contingent value rights or CVRs, which entitled the holders
to receive up to a total of 105,408,978 of Abraxas common stock under certain
circumstances, as defined. In May 2001, Abraxas issued 3,386,488 shares upon the
expiration of the CVRs.
TREASURY STOCK
In March 1996, the Board of Directors authorized the purchase in the
open market of up to 500,000 shares of the Company's outstanding common stock,
the aggregate purchase price not to exceed $3,500,000. During the year ended
December 31, 2000, 38,800 shares with an aggregate cost of $78,000 were
purchased. During the years ended December 31, 2001 and 2002, the Company did
not purchase any shares of its common stock for treasury stock.
F-19
<Page>
7. STOCK OPTION PLANS AND WARRANTS
STOCK OPTIONS
The Company grants options to its officers, directors, and key employees
under various stock option and incentive plans.
During 2001, the Company's stockholders approved an amendment to the
Abraxas Petroleum Corporation 1994 Long Term Incentive Plan to increase the
number of shares of Abraxas common stock reserved for issuance under the plan to
5,000,000. The additional shares were necessary to accommodate the grant of
Abraxas options to Old Grey Wolf option holders in connection with the
acquisition of the minority interest in Old Grey Wolf in September 2001 (see
Note 5), and for the re-issuance of outstanding options granted under the
Abraxas Petroleum Corporation 2000 Long Term Incentive Plan, which was
terminated in 2001. The options were re-issued at the same exercise price and
term as the original issuances.
The Company's various stock option plans have authorized the grant of
options to management, employees and directors for up to approximately 5.7
million shares of the Company's common stock. All options granted have ten year
terms and vest and become fully exercisable over three to four years of
continued service at 25% to 33% on each anniversary date. At December 31, 2002
approximately 2.2 million options remain available for grant.
A summary of the Company's stock option activity, and related
information for the years ended December 31, follows:
<Table>
<Caption>
2000 2001 2002
-------------------------- ------------------------------ -------------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
OPTIONS AVERAGE EXERCISE OPTIONS AVERAG EEXERCISE OPTIONS AVERAGE EXERCISE
(000S) PRICE (000S) PRICE (1) (000S) PRICE
------- ---------------- ----------- ---------------- ------------ ----------------
Outstanding-beginning of
year ................... 1,890 $ 1.82 4,042 $ 3.37 4,942 $ 3.28
Granted ................... 2,240 4.62 918 2.81 521 0.68
Exercised ................. - - (8) 1.95 - -
Forfeited/Expired ......... (88) 1.89 (10) 1.79 (2,158) 4.84
------- ----------- ------------
Outstanding-end of year ... 4,042 $ 3.37 4,942 $ 3.28 3,305 $ 1.85
======= =========== ============
Exercisable at end of year 1,067 $ 1.99 2,259 $ 2.65 2,136 $ 1.91
======= =========== ============
Weighted-average fair
value of options
granted during the year. $ 1.21 $ 1.19 $ 0.63
</Table>
(1) In September 2001, the Abraxas Petroleum Corporation 2000 Long Term
Incentive Plan was terminated, and options granted under the plan were
reissued under the Abraxas Petroleum Corporation 1994 Long Term Incentive
Plan at the same option price and term.
The following table represents the range of option prices and the
weighted average remaining life of outstanding options as of December 31, 2002:
<Table>
<Caption>
Options outstanding Exercisable
------------------------------------------ --------------------------------------
Weighted Weighted
average average
Number remaining exercise Number Weighted average
Exercise price outstanding life price exercisable exercise price
--------------- ------------ --------- --------- ----------- ------------------
$0.50 - 0.97 795,000 8.8 $ 0.77 300,000 $ 0.97
$1.22 - 1.85 688,996 6.9 1.46 336,895 1.43
$2.01 - 2.21 1,507,494 4.5 2.08 1,394,107 2.07
$3.00 - 3.71 79,812 6.5 3.11 43,609 3.17
$4.13 - 4.83 234,035 8.1 4.82 61,538 4.78
</Table>
F-20
<Page>
STOCK AWARDS
In addition to stock options granted under the plans described above,
the 1994 Long-Term Incentive Plan also provides for the right to receive
compensation in cash, awards of common stock, or a combination thereof. There
were no awards in 2000, 2001 or 2002.
The Company also has adopted the Restricted Share Plan for Directors
which provides for awards of common stock to non-employee directors of the
Company who did not, within the year immediately preceding the determination of
the director's eligibility, receive any award under any other plan of the
Company. In 2000, the Company made direct awards of common stock of 12,753
shares, at weighted average fair value $0.94 per share. The Company recorded
compensation expense of $11,900 for the year ended December 31, 2000. There were
no direct awards of common stock in 2001 or 2002.
STOCK WARRANTS AND OTHER
In 2000, the Company issued 950,000 warrants in conjunction with a
consulting agreement. Each is exercisable for one share of common stock at an
exercise price of $3.50 per share. These warrants have a four-year term
beginning July 1, 2000. The Company recorded approximately $219,000 of
compensation expense which is included in other expense in 2000. In addition,
the Company paid cash compensation of $360,000 and $191,000 in 2000 and 2001,
respectively, under the agreement.
At December 31, 2002, the Company has approximately 6.4 million shares
reserved for future issuance for conversion of its stock options, warrants, and
incentive plans for the Company's directors, employees and consultants.
8. INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. Significant
components of the Company's deferred tax liabilities and assets are as follows:
<Table>
<Caption>
DECEMBER 31
------------------------
2001 2002
---------- ----------
(In thousands)
Deferred tax liabilities:
U.S. full cost pool ..................................................... $ 2,714 $ -
Canadian full cost pool.................................................. 24,809 -
---------- ----------
Total deferred tax liabilities ............................................ 27,523 -
Deferred tax assets:
U.S. full cost pool...................................................... - 2,168
Canadian full cost pool.................................................. - 9,787
Depletion ............................................................... 2,035 2,778
Net operating losses ("NOL")............................................. 42,264 58,811
Investment in foreign subsidiaries....................................... - 32,038
Other ................................................................... 2,273 1,364
---------- ----------
Total deferred tax assets ................................................. 46,572 106,946
Valuation allowance for deferred tax assets ............................... (39,670) (99,126)
---------- ----------
Net deferred tax assets ................................................... 6,902 7,820
---------- ----------
Net deferred tax liabilities (assets) ..................................... $ 20,621 $ (7,820)
========== ==========
</Table>
F-21
<Page>
Significant components of the provision (benefit) for income taxes are
as follows:
<Table>
<Caption>
2000 2001 2002
---------- ---------- ----------
Current:
Federal.............................................................. $ - $ 505 $ -
Foreign ............................................................. (1,233) - -
---------- ---------- ----------
$ (1,233) $ 505 $
========== ========== ==========
Deferred:
Federal ............................................................. $ 3,433 $ - $ -
Foreign ............................................................. 1,505 1,897 29,697
---------- ---------- ----------
$ 4,938 $ 1,897 $ 29,697
========== ========== ==========
</Table>
At December 31, 2002 the Company had, subject to the limitation
discussed below, $166.7 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 US $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 the
January 2003 transactions described in Note 2, certain of the loss carryforward
may be utilized.
At December 31, 2002, the Company was no longer permanently reinvested
with respect to its foreign subsidiaries, see Note 2. As a result, the Company
recorded net deferred tax assets of $32.0 million related to its investment in
foreign subsidiaries, offset by an equivalent valuation allowance due to
uncertainties as to the future utilization of these amounts.
As a result of the acquisition of certain partnership interests and
crude oil and natural gas properties in 1990 and 1991, an ownership change under
Section 382 occurred in December 1991. Accordingly, it is expected that the use
of the U.S. net operating loss carryforwards generated prior to December 31,
1991 of $3.2 million will be limited to approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an
unrelated corporation. The use of net operating loss carryforwards of the
acquired corporation of $257,000 acquired in the acquisition are limited to
approximately $115,000 per year.
As a result of the issuance of additional shares of common stock for
acquisitions and sales of common stock, an additional ownership change under
Section 382 occurred in October 1993. Accordingly, it is expected that the use
of all U.S. net operating loss carryforwards generated through October 1993
(including those subject to the 1991 and 1992 ownership changes discussed above)
of $6.6 million will be limited as described above and in the following
paragraph.
An ownership change under Section 382 occurred in December 1999,
following the issuance of additional shares, as described in Note 4. It is
expected that the annual use of U.S. net operating loss carryforwards subject to
this Section 382 limitation will be limited to approximately $363,000, subject
to the lower limitations described above. Future changes in ownership may
further limit the use of the Company's carryforwards. In 2000 assets with built
in gains were sold, increasing the Section 382 limitation for 2001 by
approximately $31.0 million.
The annual Section 382 limitation may be increased during any year,
within 5 years of a change in ownership, in which built-in gains that existed on
the date of the change in ownership are recognized.
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.
The reconciliation of income tax computed at the U.S. federal statutory
tax rates to income tax expense is:
<Table>
<Caption>
DECEMBER 31
-----------------------------------------------
2000 2001 2002
------------- -------------- -------------
(In thousands)
Tax (expense) benefit at U.S.
statutory rates (35%) .............. $ (3,965) $ 5,318 $ 51,878
</Table>
F-22
<Page>
<Table>
(Increase) decrease in deferred tax
asset valuation allowance .......... 1,371 (4,907) (59,456)
NOL utilization - gain on debt ....... (603) - -
Write-down of non-tax basis assets.... - (2,194) (7,009)
Higher effective rate of foreign 7,349
operations.......................... (1,098) (136)
Percentage depletion ................. 363 596 683
Investment in foreign subsidiaries ... - - 35,604
Other ................................ 227 (1,079) 648
------------- -------------- -------------
$ (3,705) $ (2,402) $ 29,697
============= ============== =============
</Table>
9. RELATED PARTY TRANSACTIONS
Accounts receivable - Other includes approximately $48,365 and $51,211
as of December 31, 2001 and 2002, respectively, representing amounts due from
officers and stockholders relating to advances made to employees.
Wind River Resources Corporation ("Wind River"), all of the capital
stock of which is owned by the Company's President, owns a twin-engine airplane.
The airplane is available for business use by the employees of the Company from
time to time. The Company paid Wind River a total of $336,000, $314,000 and
$345,000 in 2000, 2001 and 2002 respectively, for Wind River's operating cost
associated with the Company's use of the plane.
10. COMMITMENTS AND CONTINGENCIES
OPERATING LEASES
During the years ended December 31, 2000, 2001 and 2002, the Company
incurred rent expense related to leasing office facilities of approximately
$465,000, $519,000 and $236,000, respectively. Future minimum rental payments
are as follows at December 31, 2002.
<Table>
<Caption>
2003 ................................................... $ 336,000
2004 ................................................... 236,000
2005 ................................................... 236,000
2006 ................................................... 177,000
Thereafter ............................................. -
</Table>
LITIGATION AND CONTINGENCIES
In 2001 the Company and the Partnership (see Note 4) 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
related to the responsibility for year 2000 ad valorem taxes 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 has 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
interest in the judgment. In 2002 the Company recorded $201,000 in other expense
representing its share of the ongoing legal cost related to this matter.
In late 2000, the Company received a Final De Minimis Settlement Offer
from the United States Environmental Protection Agency concerning the Casmalia
Disposal Site, Santa Barbara County, California. The Company's liability for the
cleanup at the Superfund site is based on a 1992 acquisition, which is alleged
to have transported or arranged for the transportation of oil field waste and
drilling muds to the Superfund site. The Company has engaged California counsel
to evaluate the notice of proposed de minimis settlement and its notice of
potential strict liability under the Comprehensive Environmental Response,
Compensation and Liability Act. Defense of the action is handled through a joint
group of oil companies, all of which are claiming a petroleum exclusion that
limits the Company's liability. The potential financial exposure and any
settlement posture has yet not been developed, but is considered by the Company
to be immaterial.
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 December 31, 2002, 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.
F-23
<Page>
11. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted
earnings per share:
<Table>
<Caption>
2000 2001 2002
--------------- --------------- ---------------
Numerator:
Numerator for basic and diluted earnings per
share - net income (loss) available to common
stockholders ....................................... $ 8,449,000 $ (19,718,000) $ (118,527,000)
=============== =============== ===============
Denominator:
Denominator for basic earnings per share -
weighted-average shares ............................ 22,615,777 25,788,571 29,979,397
Effect of dilutive securities:
Stock options, warrants and CVRs ................... 10,011,987 - -
--------------- --------------- ---------------
Dilutive potential common shares Denominator for
diluted earnings per share - adjusted weighted
-average shares and assumed conversions ............ 32,627,764 25,788,571 29,979,397
=============== =============== ===============
Basic earnings (loss) per share:
Net income (loss) per common share ............... $ 0.37 $ (0.76) $ (3.95)
=============== =============== ===============
Diluted earnings (loss) per share:
Net income (loss) per common share - diluted .... $ 0.26 $ (0.76) $ (3.95)
=============== =============== ===============
</Table>
For the year ended December 31, 2000, 2001 and 2002, 3.0 million shares,
4.3 million shares and 5.9 million shares respectively, were excluded from the
calculation of diluted earnings per share since their inclusion would have been
anti-dilutive.
12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The operating results for each of the quarters in the two year period
ended December 31, 2002 have been restated to give effect to the restatement
related to amounts previously reported as discontinued operations being
reflected as continuing operations, as discussed in Note 20.
Selected results of operations for each of the fiscal quarters during
the years ended December 31, 2001 and 2002 are as follows:
<Table>
<Caption>
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
-------------- -------------- -------------- --------------
(In thousands, except per share data)
Year Ended December 31, 2001
Net revenue - as reported ........... $ 13,217 $ 9,818 $ 7,777 $ 4,963
Net revenue - as restated ........... 29,086 21,116 14,901 12,140
Operating income (loss) - as reported. 4,709 5,565 2,284 (1,293)
Operating income (loss) - as ......... 12,112 9,002 2,113 (4,102)
restated
Net income (loss) - as reported ..... 255 (1,274) (5,849) (12,850)
Net income (loss) - as restated ..... 255 (1,274) (5,849) (12,850)
Net income (loss) per common share -
basic and diluted - as reported .... $ 0.01 $ (0.05) $ (0.22) $ (0.43)
Net income (loss) per common share -
basic and diluted - as restated .... $ 0.01 $ (0.05) $ (0.22) $ (0.43)
Year Ended December 31, 2002
</Table>
F-24
<Page>
<Table>
Net revenue - as reported ............ $ 4,616 $ 5,759 $ 5,012 $ 6,920
Net revenue - as restated ........... 11,807 14,235 11,061 17,217
Operating income (loss) - as reported. (741) (33,282) (560) 827
Operating income (loss) - as restated. (735) (115,879) 490 5,221
Net income (loss) - as reported ...... (8,699) (95,690) (8,438) (5,700)
Net income (loss) - as restated ...... (8,699) (95,690) (8,438) (5,700)
Net income (loss) per common share -
basic and diluted - as reported .... $ (0.29) $ (3.19) $ (0.28) $ (0.19)
Net income (loss) per common share-
basic and diluted - as restated .... $ (0.29) $ (3.19) $ (0.28) $ (0.19)
</Table>
During the second quarter of 2002, the Company incurred a ceiling
limitation write-down of $116.0 million. During the fourth quarter of 2001, the
Company incurred a ceiling limitation write-down of $2.6 million, which was
determined using realized prices at March 22, 2002. Had year-end 2001 realized
prices been used, the write-down would have been $71.3 million.
13. BENEFIT PLANS
The Company has a defined contribution plan (401(k)) covering all
eligible employees of the Company. The Company did not contribute to the plan in
2001 or 2002. The employee contribution limitations are determined by formulas,
which limit the upper one-third of the plan members from contributing amounts
that would cause the plan to be top-heavy. The employee contribution is limited
to the lesser of 20% of the employee's annual compensation or $11,000.
14. GUARANTOR CONDENSED CONSOLIDATION FINANCIAL STATEMENTS
The following table presents condensed consolidating balance sheets of
Abraxas, as a parent company, and its significant subsidiaries, Canadian Abraxas
and Old Grey Wolf, as of December 31, 2001 and 2002 and the related
consolidating statements of operations and cash flows for the years ended
December 31, 2000, 2001 and 2002. Canadian Abraxas is a guarantor of the First
Lien Notes ($63.5 million) and jointly and severally liable with Abraxas for the
Second Lien Notes ($190.2 million) and the Old Notes ($801,000). Old Grey Wolf
is a non-guarantor with respect to the First Lien Notes and the Old Notes. The
following condensed financial statements have been restated - see Note 20.
CONDENSED CONSOLIDATING PARENT COMPANY, RESTRICTED SUBSIDIARIES AND
NON-GUARANTOR BALANCE SHEET
DECEMBER 31, 2002
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS NON- ABRAXAS
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- PETROLEUM
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS CORPORATION
INC. PARENT (CANADIAN (OLD GREY AND AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ---------- ------------ -------------
ASSETS:
Current assets:
Cash .................................. $ 557 $ 2,188 $ 2,137 $ - $ 4,882
Accounts receivable, less allowance for
doubtful accounts ................... 4,482 4,782 11,938 (11,157) 10,045
Equipment inventory ................... 860 142 12 - 1,014
Other current assets .................. 316 682 242 - 1,240
----------- ---------- ---------- ------------ ------------
Total current assets ........... 6,215 7,794 14,329 (11,157) 17,181
Property and equipment - net ............. 74,435 38,858 37,101 - 150,394
Deferred financing fees, net ............. 2,970 688 2,013 - 5,671
Deferred income taxes and other assets ... 108,558 - 7,820 (108,199) 8,179
----------- ---------- ---------- ------------ ------------
Total assets .......................... $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425
=========== ========== ========== ============ ============
LIABILITIES AND STOCKHOLDERS' DEFICIT:
Current liabilities:
Accounts payable ...................... $ 15,928 $ 766 $ 6,398 $ (10,973) $ 12,119
</Table>
F-25
<Page>
<Table>
<Caption>
Accrued interest ...................... 5,000 1,009 - - 6,009
Other accrued expenses ................ 1,162 - - - 1,162
Current maturities of long-term debt .. 63,500 - - - 63,500
----------- ---------- ---------- ------------ ------------
Total current liabilities ........... 85,590 1,775 6,398 (10,973) 82,790
Long-term debt ........................... 138,350 52,629 45,964 - 236,943
Future site restoration .................. - 3,171 775 - 3,946
----------- ---------- ---------- ------------ ------------
223,940 57,575 53,137 (10,973) 323,679
Stockholders' equity (deficit) ........... (31,762) (10,235) 8,126 (108,383) (142,254)
----------- ---------- ---------- ------------ ------------
Total liabilities and stockholders' equity
(deficit) $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425
=========== ========== ========== ============ ============
</Table>
(1) Includes amounts for insignificant U.S. subsidiaries, Sandia and Wamsutter,
which are guarantors of the First and Second Lien Notes. Sandia is also a
guarantor of the Old Notes. Additionally, these subsidiaries are designated
as Restricted Subsidiaries along with Canadian Abraxas.
CONDENSED CONSOLIDATING PARENT COMPANY, RESTRICTED SUBSIDIARIES AND
NON-GUARANTOR BALANCE SHEET
DECEMBER 31, 2001
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS NON- ABRAXAS
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- PETROLEUM
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS CORPORATION
INC. PARENT (CANADIAN (OLD GREY AND AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
-----------------------------------------------------------------------------
ASSETS:
Current assets:
Cash .................................. $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
Accounts receivable, less allowance for
doubtful accounts ................... 17,184 792 6,782 (16,711) 8,047
Equipment inventory ................... 1,061 178 12 - 1,251
Other current assets .................. 250 99 94 - 443
----------- ---------- ---------- ------------ -----------
Total current assets ................ 22,088 2,314 9,655 (16,711) 17,346
Property and equipment - net ............. 116,462 122,486 42,946 - 281,894
Deferred financing fees - net ........... 2,779 1,042 107 - 3,928
Other assets ............................. 108,801 784 6,281 (115,418) 448
----------- ---------- ---------- ------------ -----------
Total assets .......................... $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616
=========== ========== ========== ============ ===========
LIABILITIES AND STOCKHOLDERS' DEFICIT:
Current liabilities:
Accounts payable ...................... $ 10,642 $ 17,009 $ 9,472 $ (22,985) $ 14,138
Accrued interest ...................... 5,000 1,009 4 - 6,013
Other accrued expenses ................ 1,052 - 64 - 1,116
Hedge liability ....................... 438 220 - - 658
Current maturities of long-term debt .. 415 - - - 415
----------- ---------- ---------- ------------ -----------
Total current liabilities ........... 17,547 18,238 9,540 (22,985) 22,340
Long-term debt ........................... 209,611 52,629 22,944 - 285,184
Deferred income taxes .................... - 17,718 2,903 - 20,621
Future site restoration .................. - 3,399 657 - 4,056
----------- ---------- ---------- ------------ -----------
227,158 91,984 36,044 (22,985) 332,201
Stockholders' equity (deficit) ........... 22,972 34,642 22,945 (109,144) (28,585)
----------- ---------- ---------- ------------ -----------
Total liabilities and stockholders' equity
(deficit) $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616
=========== ========== ========== ============ ===========
</Table>
CONDENSED CONSOLIDATING PARENT COMPANY, RESTRICTED SUBSIDIARY AND
NON-GUARANTOR STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2002
(IN THOUSANDS)
F-26
<Page>
<Table>
<Caption>
ABRAXAS NON- ABRAXAS
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- PETROLEUM
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS CORPORATION
INC. PARENT (CANADIAN (OLD GREY AND AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ---------- ------------ ------------
Revenues:
Oil and gas production revenues ......... $ 20,835 $ 14,726 $ 15,301 $ - $ 50,862
Gas processing revenues ................. - 1,955 465 2,420
Rig revenues ............................ 635 - - - 635
Other ................................... 71 152 180 - 403
----------- ---------- ---------- ------------ ------------
21,541 16,833 15,946 - 54,320
Operating costs and expenses:
Lease operating and production taxes .... 7,639 3,751 3,850 - 15,240
Depreciation, depletion, and amortization 9,194 10,633 6,712 - 26,539
Proved property impairment .............. 28,178 60,501 27,314 - 115,993
Rig operations .......................... 567 - - - 567
General and administrative .............. 4,045 1,312 1,527 - 6,884
----------- ---------- ---------- ------------ ------------
49,623 76,197 39,403 - 165,223
----------- ---------- ---------- ------------ ------------
Operating income (loss) .................... (28,082) (59,364) (23,457) - (110,903)
Other (income) expense:
Interest income ......................... (92) - - - (92)
Amortization of deferred financing fees . 1,325 366 404 - 2,095
Interest expense ........................ 24,689 6,665 2,796 - 34,150
Other ................................... 1,168 - - - 1,168
----------- ---------- ---------- ------------ ------------
27,090 7,031 3,200 - 37,321
----------- ---------- ---------- ------------ ------------
Income (loss) before income tax ............ (55,172) (66,395) (26,657) - (148,224)
Income tax expense (benefit) ............... - (18,522) (11,175) - (29,697)
----------- ---------- ---------- ------------ ------------
Net income (loss) .......................... $ (55,172) $ (47,873) $ (15,482) $ - $ (118,527)
=========== ========== ========== ============ ============
</Table>
CONDENSED CONSOLIDATING PARENT COMPANY, RESTRICTED SUBSIDIARY AND
NON-GUARANTOR STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS NON- ABRAXAS
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- PETROLEUM
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS CORPORATION
INC. PARENT (CANADIAN (OLD GREY AND AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ---------- ------------ ------------
Revenues:
Oil and gas production revenues ......... $ 34,934 $ 24,308 $ 13,959 $ - $ 73,201
Gas processing revenues ................. - 2,008 430 - 2,438
Rig revenues ............................ 756 - - - 756
Other ................................... 85 471 292 - 848
----------- ---------- ---------- ------------ ------------
35,775 26,787 14,681 - 77,243
Operating costs and expenses:
Lease operating and production taxes .... 9,302 6,836 2,478 - 18,616
Depreciation, depletion, and amortization 12,336 14,707 5,441 - 32,484
Proved property impairment .............. - 2,638 - - 2,638
Rig operations .......................... 702 - - - 702
General and administrative .............. 3,742 1,720 983 - 6,445
General and administrative (Stock-based
Compensation) ......................... (2,767) - - - (2,767)
----------- ---------- ---------- ------------ ------------
23,315 25,901 8,902 - 58,118
----------- ---------- ---------- ------------ ------------
Operating income (loss) .................... 12,460 886 5,779 - 19,125
</Table>
F-27
<Page>
<Table>
Other (income) expense:
Interest income ......................... (1,242) - - 1,164 (78)
Amortization of deferred financing fees . 1,907 361 - - 2,268
Interest expense ........................ 25,086 7,117 484 (1,164) 31,523
Other ................................... 1,052 - - - 1,052
----------- ---------- ---------- ------------ ------------
26,803 7,478 484 - 34,765
----------- ---------- ---------- ------------ ------------
Income (loss) before income tax ............ (14,343) (6,592) 5,295 - (15,640)
Income tax expense (benefit) ............... 505 (80) 1,977 - 2,402
Minority interest in income of consolidated
foreign subsidiary ...................... - - 1,676 - 1,676
----------- ---------- ---------- ------------ ------------
Net income (loss) ......................... $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
=========== ========== ========== ============ ============
</Table>
CONDENSED CONSOLIDATING PARENT COMPANY, RESTRICTED SUBSIDIARY AND
NON-GUARANTOR STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS NON- ABRAXAS
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- PETROLEUM
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS CORPORATION
INC. PARENT (CANADIAN (OLD GREY AND AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ---------- ------------ ------------
Revenues:
Oil and gas production revenues ......... $ 32,165 $ 27,425 $ 13,383 $ - $ 72,973
Gas processing revenues ................. - 2,271 446 2,717
Rig revenues ............................ 505 - - - 505
Other ................................... 216 170 19 - 405
----------- ---------- ---------- ------------ ------------
32,886 29,866 13,848 - 76,600
Operating costs and expenses:
Lease operating and production taxes .... 7,755 8,695 2,333 - 18,783
Depreciation, depletion, and amortization 12,328 18,126 5,403 - 35,857
Rig operations .......................... 717 - - - 717
General and administrative .............. 4,115 1,484 934 - 6,533
General and administrative (Stock-based
Compensation) ......................... 2,767 - - - 2,767
----------- ---------- ---------- ------------ ------------
27,682 28,305 8,670 - 64,657
----------- ---------- ---------- ------------ ------------
Operating income (loss) .................... 5,204 1,561 5,178 - 11,943
Other (income) expense:
Interest income ......................... (2,277) - 1,747 (530)
Amortization of deferred financing fees . 1,660 431 - - 2,091
Interest expense ........................ 24,594 7,582 711 (1,747) 31,140
Gain on sale of equity investment ....... (33,983) - - - (33,983)
Gain on debt extinguishment ............. (1,773) - - - (1,773)
Other ................................... 1,116 447 - - 1,563
----------- ---------- ---------- ------------ ------------
(10,663) 8,460 711 - (1,492)
----------- ---------- ---------- ------------ ------------
Income (loss) before income tax ............ 15,867 (6,899) 4,467 - 13,435
Income tax expense (benefit) ............... 3,433 (1,658) 1,930 3,705
Minority interest in income of consolidated
foreign subsidiary ...................... - - 1,281 1,281
----------- ---------- ---------- ------------ ------------
Net income (loss) .......................... $ 12,434 $ (5,241) $ 1,256 $ - $ 8,449
=========== ========== ========== ============ ============
</Table>
CONDENSED CONSOLIDATING PARENT, RESTRICTED SUBSIDIARY AND NON-GUARANTOR
STATEMENT OF CASH FLOW
FOR THE YEAR ENDED DECEMBER 31, 2002
(IN THOUSANDS)
F-28
<Page>
<Table>
<Caption>
ABRAXAS NON-
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- ABRAXAS
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS PETROLEUM
INC. PARENT (CANADIAN (OLD GREY AND CORPORATION AND
COMPANY (1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
---------- ---------- ---------- ------------ ---------------
OPERATING ACTIVITIES
Net income (loss) .......................... $ (55,172) $ (47,873) $ (15,482) $ - $ (118,527)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization ........................ 9,194 10,633 6,712 - 26,539
Proved property impairment ............ 28,178 60,501 27,314 - 115,993
Deferred income tax (benefit) expense . - (18,522) (11,175) - (29,697)
Amortization of deferred financing fees. 1,325 366 404 - 2,095
Changes in operating assets and
liabilities:
Accounts receivable ............... 18,088 (3,187) 1,114 (18,262) (2,247)
Equipment inventory ............... 201 - - - 201
Other ............................. 381 (177) (78) - 126
Accounts payables and accrued
expenses ........................ (47) 479 (3,251) - (2,819)
----------- ---------- ---------- ------------ ---------------
Net cash provided by (used in)operations ... 2,148 2,220 5,558 (18,262) (8,336)
INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ........... (5,070) (4,926) (28,916) - (38,912)
Proceeds from sale of oil and gas
properties .............................. 9,725 21,789 2,362 - 33,876
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by investing
activities .............................. 4,655 16,863 (26,554) - (5,036)
FINANCING ACTIVITIES
Proceeds from long-term borrowings ......... - - 20,551 - 20,551
Payments on long-term borrowings ........... (8,176) (18,262) - 18,262 (8,176)
Deferred financing fees .................... (1,663) 146 (22) - (1,539)
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by financing
activities .............................. (9,839) (18,116) 20,529 18,262 10,836
----------- ---------- ---------- ------------ ---------------
Effect of exchange rate changes on cash .... - (24) (163) - (187)
----------- ---------- ---------- ------------ ---------------
Increase (decrease) in cash ................ (3,036) 943 (630) - (2,723)
Cash at beginning of year .................. 3,593 1,245 2,767 - 7,605
----------- ---------- ---------- ------------ ---------------
Cash at end of year ........................ $ 557 $ 2,188 $ 2,137 $ - $ 4,882
=========== ========== ========== ============ ===============
</Table>
CONDENSED CONSOLIDATING PARENT, RESTRICTED SUBSIDIARY AND NON-GUARANTOR
STATEMENT OF CASH FLOW
FOR THE YEAR ENDED DECEMBER 31, 2001
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS NON-
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- ABRAXAS
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS PETROLEUMN
INC. PARENT (CANADIAN (OLD GREY AND CORPORATIO AND
COMPANY (1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ---------- ------------ ---------------
OPERATING ACTIVITIES
Net income (loss) .......................... $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Minority interest in income of foreign
subsidiary .......................... - - 1,676 - 1,676
Loss on sale of equity investment ..... 845 - - - 845
Depreciation, depletion, and
amortization ........................ 12,336 14,707 5,441 - 32,484
Proved property impairment ............ - 2,638 - 2,638
Deferred income tax (benefit) expense . - (80) 1,977 - 1,897
Amortization of deferred financing fees. 1,907 361 - - 2,268
Stock-based compensation .............. (2,767) - - - (2,767)
Changes in operating assets and
liabilities:
Accounts receivable ............... 28,804 (9,721) (6,390) - 12,693
Equipment inventory ............... (76) - - - (76)
Other ............................. (281) - 175 - (106)
Accounts payables and accrued
expenses ........................ (12,915) (2,254) (402) - (15,571)
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by operating
activities .............................. 13,005 (861) 4,119 - 16,263
INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ........... (19,126) (15,313) (22,617) - (57,056)
Proceeds from sale of oil and gas
properties .............................. 9,677 15,882 3,379 - 28,938
Acquisition of minority interest ........... (2,679) - - - (2,679)
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by investing
activities .............................. (12,128) 569 (19,238) - (30,797)
----------- ---------- ---------- ------------ ---------------
FINANCING ACTIVITIES
Proceeds form issuance of common stock ..... 16 - - - 16
Proceeds from long-term borrowings ......... 11,700 - 18,295 - 29,995
Payments on long-term borrowings ........... (9,326) - - - (9,326)
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by financing ...... 2,390 - 18,295 - 20,685
activities
----------- ---------- ---------- ------------ ---------------
3,267 (292) 3,176 - 6,151
Effect of exchange rate changes on cash .... - (141) (409) - (550)
----------- ---------- ---------- ------------ ---------------
Increase (decrease) in cash ................ 3,267 (433) 2,767 - 5,601
Cash at beginning of year .................. 326 1,678 - - 2,004
----------- ---------- ---------- ------------ ---------------
Cash at end of year ........................ $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
=========== ========== ========== ============ ===============
</Table>
F-29
<Page>
CONDENSED CONSOLIDATING PARENT, RESTRICTED SUBSIDIARY
AND NON-GUARANTOR STATEMENT OF CASH FLOW
FOR THE YEAR ENDED DECEMBER 31, 2000
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS NON-
PETROLEUM RESTRICTED GUARANTOR RECLASSIFI- ABRAXAS
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS PETROLEUMN
INC. PARENT (CANADIAN (OLD GREY AND CORPORATIO AND
COMPANY (1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ---------- ------------ ---------------
OPERATING ACTIVITIES
Net income (loss) .......................... $ 12,434 $ (5,241) $ 1,256 $ - $ 8,449
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Minority interest in income of foreign
subsidiary .......................... - - 1,281 - 1,281
Gain on extinguishment of debt ........ (1,773) - - - (1,773)
Gain on sale of equity investment ..... (33,983) - - - (33,983)
Depreciation, depletion, and
amortization ........................ 12,329 18,126 5,402 35,857
Deferred income tax expense (benefit) . 3,433 (153) 1,658 - 4,938
Amortization of deferred financing fees. 1,660 431 - - 2,091
Stock-based compensation .............. 2,767 - - - 2,767
Issuance of common stock and warrants
for compensation .................... 265 - - - 265
Changes in operating assets and
liabilities:
Accounts receivable ............... 8 (3,461) (3,583) - (7,036)
Equipment inventory ............... (538) - - - (538)
Other ............................. (184) (1,618) (37) - (1,839)
Accounts payables and accrued
expenses ........................ 5,357 378 5,158 - 10,893
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by operations ..... 1,775 8,462 11,135 - 21,372
INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ........... (39,767) (15,649) (18,996) - (74,412)
Proceeds from sale of oil and gas
properties .............................. 5,542 7,393 8,222 - 21,157
Proceeds from sale of equity investment .... 34,482 - - - 34,482
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by investing
activities .............................. 257 (8,256) (10,774) -
(18,773)
----------- ---------- ---------- ------------ ---------------
FINANCING ACTIVITIES
Purchase of treasury stock, net ............ (78) - - - (78)
Proceeds from long-term borrowings ......... 6,400 - - - 6,400
Payments on long-term borrowings ........... (9,979) - (184) - (10,163)
Deferred financing fees .................... 23 - - - 23
----------- ---------- ---------- ------------ ---------------
Net cash provided (used) by financing
activities .............................. (3,634) - (184) - (3,818)
----------- ---------- ---------- ------------ ---------------
(1,602) 206 177 - (1,219)
Effect of exchange rate changes on cash .... - (399) (177) - (576)
----------- ---------- ---------- ------------ ---------------
Increase (decrease) in cash ................ (1,602) (193) - - (1,795)
Cash at beginning of year .................. 1,928 1,871 - - 3,799
----------- ---------- ---------- ------------ ---------------
Cash at end of year ........................ $ 326 $ 1,678 $ - $ - $ 2,004
=========== ========== ========== ============ ===============
</Table>
F-30
<Page>
15. BUSINESS SEGMENTS
The Company conducts its operations through two geographic segments, the
United States and Canada, and is engaged in the acquisition, development, and
production of crude oil and natural gas and the processing of natural gas in
each country. The Company's significant operations are located in the Texas Gulf
Coast, the Permian Basin of western Texas, and Canada. Identifiable assets are
those assets used in the operations of the segment. Corporate assets consist
primarily of deferred financing fees and other property and equipment. The
Company's revenues are derived primarily from the sale of crude oil, condensate,
natural gas liquids, and natural gas to marketers and refiners and from
processing fees from the custom processing of natural gas. As a general policy,
collateral is not required for receivables; however, the credit of the Company's
customers is regularly assessed. The Company is not aware of any significant
credit risk relating to its customers and has not experienced significant credit
losses associated with such receivables.
In 2002, four customers accounted for approximately 79% of consolidated
oil and natural gas production revenue. Three customers accounted for
approximately 77% of United States revenue and one customer accounted for
approximately 80% of revenue in Canada. In 2001, three customers accounted for
approximately 41% of oil and natural gas production revenues. Three customers
accounted for approximately 76% of United States revenue and five customers
accounted for approximately 76% of revenue in Canada. In 2000, two customers
accounted for approximately 26% of oil and natural gas production revenues and
gas processing revenues.
Business segment information about the Company's 2000 operations in different
geographic areas is as follows:
<Table>
<Caption>
U.S. CANADA TOTAL
---------- ---------- ----------
(In thousands)
Revenues ................................................... $ 32,886 $ 43,714 $ 76,600
========== ========== ==========
Operating profit ........................................... $ 12,446 $ 6,739 $ 19,185
========== ==========
</Table>
F-31
<Page>
<Table>
General corporate .......................................... (7,602)
Net interest expense and amortization of
deferred financing fees ................................. (32,701)
Other income (net) ......................................... 34,553
----------
Income before income taxes .............................. $ 13,435
==========
Identifiable assets at December 31, 2000 ................... $ 132,327 $ 197,229 $ 329,556
========== ==========
Corporate assets ........................................... 6,004
----------
Total assets ............................................ $ 335,560
==========
</Table>
F-32
<Page>
Business segment information about the Company's 2001 operations in different
geographic areas is as follows:
<Table>
<Caption>
U.S. CANADA TOTAL
---------- ---------- ----------
(In thousands)
Revenues ................................................... $ 35,775 $ 41,468 $ 77,243
========== ========== ==========
Operating profit ........................................... $ 13,795 $ 6,665 $ 20,460
========== ==========
General corporate .......................................... (1,335)
Net interest expense and amortization of
deferred financing fees ................................. (33,713)
Other expense .............................................. (1,052)
----------
Loss before income taxes ................................ $ (15,640)
==========
Identifiable assets at December 31, 2001 ................... $ 124,993 $ 174,063 $ 299,056
========== ==========
Corporate assets ........................................... 4,560
----------
Total assets ............................................ $ 303,616
==========
</Table>
Business segment information about the Company's 2002 operations in different
geographic areas is as follows:
<Table>
<Caption>
U.S. CANADA TOTAL
---------- ---------- ----------
(In thousands)
Revenues ................................................... $ 21,541 $ 32,779 $ 54,320
========== ========== ==========
Operating loss ............................................. $ (23,677) $ (82,821) $ (106,498)
========== ==========
General corporate .......................................... (4,405)
Net interest expense and amortization of
deferred financing fees ................................. (36,153)
Other expense .............................................. (1,168)
----------
Loss before income taxes ................................ $ (148,224)
==========
Identifiable assets at December 31, 2002 ................... $ 81,025 $ 94,059 $ 175,084
========== ==========
Corporate assets ........................................... 6,341
----------
Total assets ............................................ $ 181,425
==========
</Table>
16. HEDGING PROGRAM AND DERIVATIVES
On January 1, 2001, the Company adopted SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities" as amended and interpreted. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, the Company
uses only cash flow hedges and the remaining discussion will relate exclusively
to this
F-33
<Page>
type of derivative instrument. If the derivative qualifies for hedge accounting,
the gain or loss on the derivative is deferred in Other Comprehensive Income
(Loss), a component of Stockholders' Equity, to the extent that the hedge is
effective.
The relationship between the hedging instrument and the hedged item must
be highly effective in achieving the offset of changes in cash flows
attributable to the hedged risk both at the inception of the contract and on an
ongoing basis. Hedge accounting is discontinued prospectively when a hedge
instrument becomes ineffective. Gains and losses deferred in accumulated Other
Comprehensive Income (Loss) related to a cash flow hedge that becomes
ineffective remain unchanged until the related production is delivered. If the
Company determines that it is probable that a hedged transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
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.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, the Company recorded $31.0 million, net of tax, in Other Comprehensive
Income (Loss) representing the cumulative effect of an accounting change to
recognize the fair value of cash flow derivatives. The Company recorded cash
flow hedge derivative liabilities of $38.2 million on that date and a deferred
tax asset of $7.2 million.
For the year ended December 31, 2001, losses before tax of $12.1 million
were transferred from Other Comprehensive Income (Loss) to revenue and the fair
value of outstanding liabilities decreased by $25.5 million. The ineffective
portion of the cash flow hedges was not material at December 31, 2001.
For the year ended December 31, 2001, $566,000 of deferred net loss on
derivative instruments were recorded in Other Comprehensive Income (Loss). All
of the deferred net loss was reclassified to earnings during the next
twelve-month period.
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 Company entered into a costless collar hedge agreement with Barrett
Resources Corporation ("Barrett") for the period November 1999 through October
2000. This agreement consisted of a swap for 1,000 Bbls per day of crude oil
with the Company being paid $20.30 and paying NYMEX calendar month average, and
an additional 1,000 Bbls of crude oil per day with a floor price of $18.00 per
Bbl and a ceiling of $22.00 per Bbl. The Company realized a loss from hedges of
$20.2 million for the year ended December 31, 2000, which is accounted for in
Oil and Gas Production Revenue. At year end 2001 Barrett had a swap call on
either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day at
Barrett's option at fixed prices ($18.90 for crude oil or $2.60 to $2.95 for
natural gas) through October 31, 2002. The Company realized a loss from hedges
of $12.1 million and $3.2 million for the years ended December 31, 2001 and 2002
respectively, which is accounted for in Oil and Gas Production Revenue.
Under the terms of the New Senior Secured Credit Agreement, (see Note 2)
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. As of January 23, 2003, the Company has 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 calendar 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 calendar months of
March 2003 through February 2004.
17. COMPREHENSIVE INCOME
Comprehensive income includes net income, losses and certain items recorded
directly to Stockholders' Equity and classified as Other Comprehensive Income
(Loss). The following table illustrates the calculation of comprehensive income
for the year ended December 31, 2002:
F-34
<Page>
<Table>
<Caption>
Accumulated Other
Comprehensive Comprehensive
Income (Loss) Income (Loss)
----------------- --------------------
For the year
Ended
December 31, As of
2002 December 31,2002
----------------- --------------------
Accumulated other comprehensive loss at December 31, 2001 ........ $ (13,561)
Net loss ...................................................... $ (118,527)
-----------------
Other Comprehensive income (loss):
Hedging derivatives (net of tax) - See Note 16
Reclassification adjustment for settled hedge contracts, net
of taxes of ($596) .......................................... 2,556
Change in fair market value of outstanding hedge positions
net of taxes of $504 ........................................ (1,990)
-----------------
566
Foreign currency translation adjustment ....................... 4,292
-----------------
Other comprehensive income (loss) ................................ 4,858 4,858
----------------- --------------------
Comprehensive income (loss) ...................................... $ (113,669)
=================
Accumulated other comprehensive loss at December 31, 2002 ........ $ (8,703)
====================
</Table>
18. PROVED PROPERTY IMPAIRMENT
In accordance with SEC requirements, the estimated discounted future net
cash flows from proved reserves are generally based on prices and costs as of
the end of the year, 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 December 31, 2001, the Company's net capitalized costs of oil
and gas properties exceeded the present value of its estimated proved reserves
by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the
Canadian properties). These amounts were calculated considering 2001 year-end
prices of $19.84 per barrel for oil and $2.57 per Mcf for gas as adjusted to
reflect the expected realized prices for each of the full cost pools. The
Company did not adjust its capitalized costs for its U.S. properties because
subsequent to December 31, 2001, oil and gas prices increased such that
capitalized costs for its U.S. properties did not exceed the present value of
the estimated proved oil and gas reserves for its U.S. properties as determined
using increased realized prices on March 22, 2002 of $24.16 per Bbl for oil and
$2.89 per Mcf for gas. During the second quarter of 2002, the Company had a
ceiling limitation write-down of $116.0 million.
F-35
<Page>
19. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The accompanying table presents information concerning the Company's
crude oil and natural gas producing activities as required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities." Capitalized costs relating to oil and gas producing activities are
as follows:
<Table>
<Caption>
YEARS ENDED DECEMBER 31
--------------------------------------------------------------------------
2001 2002
----------------------------------- -----------------------------------
TOTAL U.S. CANADA TOTAL U.S. CANADA
--------- --------- --------- --------- --------- ---------
(In thousands)
Proved crude oil and natural
gas properties ........... $ 486,098 $ 284,182 $ 201,916 $ 521,309 $ 279,401 $ 241,908
Unproved properties ........ 10,626 - 10,626 7,052 - 7,052
--------- --------- --------- --------- --------- ---------
Total .................... 496,724 284,182 212,542 528,361 279,401 248,960
Accumulated depreciation,
depletion, and
amortization, and
impairment ............... (280,280) (168,124) (112,156) (420,344) (205,181) (215,163)
--------- --------- --------- --------- --------- ---------
Net capitalized costs .. $ 216,444 $ 116,058 $ 100,386 $ 108,017 $ 74,220 $ 33,797
========= ========= ========= ========= ========= =========
</Table>
Cost incurred in oil and gas property acquisitions, exploration and
development activities are as follows:
<Table>
<Caption>
YEARS ENDED DECEMBER 31
---------------------------------------------------------------------------
2000 2001
------------------------------------ ------------------------------------
TOTAL U.S. CANADA TOTAL U.S. CANADA
---------- ---------- ---------- ---------- ---------- ----------
(In thousands)
Property acquisition costs:
Proved .................. $ 7,189 $ - $ 7,189 $ - $ - $ -
Unproved ................ - - - - - -
---------- ---------- ---------- ---------- ---------- ----------
$ 7,189 $ - $ 7,189 $ - $ - $ -
========== ========== ========== ========== ========== ==========
Property development and
exploration costs ....... $ 64,873 $ 39,631 $ 25,242 $ 56,694 $ 18,867 $ 37,827
========== ========== ========== ========== ========== ==========
<Caption>
YEARS ENDED DECEMBER 31
------------------------------------
2002
------------------------------------
TOTAL U.S. CANADA (1)
---------- ---------- ----------
(In thousands)
Property acquisition costs:
Proved .................. $ - $ - $ -
Unproved ................ - - -
---------- ---------- ----------
$ - $ - $ -
========== ========== ==========
Property development and
exploration costs ....... $ 38,560 $ 4,944 $ 33,616
========== ========== ==========
</Table>
(1) Canadian costs in 2002 were primarily for exploratory purposes.
F-36
<Page>
The results of operations for oil and gas producing activities are as
follows:
<Table>
<Caption>
YEARS ENDED DECEMBER 31
--------------------------------------------------------------------------------
2000 2001
-------------------------------------- --------------------------------------
TOTAL U.S. CANADA TOTAL U.S. CANADA
---------- ---------- ---------- ---------- ---------- ----------
(In thousands)
Revenues ........................ $ 72,973 $ 32,165 $ 40,808 $ 73,201 $ 34,934 $ 38,267
Production costs ................ (18,783) (7,755) (11,028) (18,616) (9,302) (9,314)
Depreciation, depletion,
and amortization .............. (35,497) (11,968) (23,529) (32,124) (11,976) (20,148)
Proved property impairment ...... - - - (2,638) - (2,638)
General and administrative ...... (1,722) (1,118) (604) (1,565) (1,073) (492)
Income taxes (expense)
benefit ....................... (339) - (339) (2,419) - (2,419)
---------- ---------- ---------- ---------- ---------- ----------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) ........... $ 16,632 $ 11,324 $ 5,308 $ 15,839 $ 12,583 $ 3,256
========== ========== ========== ========== ========== ==========
Depletion rate per barrel
of oil equivalent, before
impact of impairment .......... $ 8.30 $ 6.19 $ 10.02 $ 8.81 $ 6.96 $ 10.45
========== ========== ========== ========== ========== ==========
<Caption>
YEARS ENDED DECEMBER 31
--------------------------------------
2002
--------------------------------------
TOTAL U.S. CANADA
---------- ---------- ----------
(In thousands)
Revenues ........................ $ 50,862 $ 20,835 $ 30,027
Production costs ................ (15,240) (7,639) (7,601)
Depreciation, depletion,
and amortization .............. (26,224) (8,879) (17,345)
Proved property impairment ...... (115,993) (28,178) (87,815)
General and administrative ...... (1,836) (1,011) (825)
Income taxes (expense)
benefit ....................... - - -
---------- ---------- ----------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) ........... $ (108,431) $ (24,872) $ (83,559)
========== ========== ==========
Depletion rate per barrel
of oil equivalent, before
impact of impairment .......... $ 8.52 $ 7.55 $ 8.94
========== ========== ==========
</Table>
F-37
<Page>
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
The following table presents the Company's estimate of its net proved
crude oil and natural gas reserves as of December 31, 2000, 2001, and 2002. The
Company's management emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates have been prepared by
independent petroleum reserve engineers.
<Table>
<Caption>
TOTAL UNITED STATES CANADA
-------------------------- -------------------------- -------------------------
LIQUID NATURAL LIQUID NATURAL LIQUID NATURAL
HYDROCARBONS GAS HYDROCARBONS GAS HYDROCARBONS GAS
------------ ---------- ------------ ---------- ------------ ----------
(BARRELS) (MCF) (BARRELS) (MCF) (BARRELS) (MCF)
(In Thousands)
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
Balance at January 1, 2000 (1) ........... 9,849 164,305 6,421 80,417 3,428 83,888
Revisions of previous estimates ........ (216) (21,342) 54 (13,441) (270) (7,901)
Extensions and discoveries ............. 791 72,498 315 57,371 476 15,127
Purchase of minerals in place .......... 254 6,822 - - 254 6,822
Production ............................. (952) (19,963) (539) (8,364) (413) (11,599)
Sale of minerals in place .............. (882) (10,993) (170) (1,075) (712) (9,918)
------------ ---------- ------------ ---------- ------------ ----------
Balance at December 31, 2000 ............. 8,844 191,327 6,081 114,908 2,763 76,419
Revisions of previous estimates ........ (628) 2,944 (688) 3,318 60 (374)
Extensions and discoveries ............. 1,064 26,329 354 4,886 710 21,443
Production ............................. (732) (17,495) (416) (7,823) (316) (9,672)
Sale of minerals in place .............. (1,746) (14,348) (924) (6,821) (822) (7,527)
------------ ---------- ------------ ---------- ------------ ----------
Balance at December 31, 2001 ............. 6,802 188,757 4,407 108,468 2,395 80,289
Revisions of previous estimates ........ (798) (29,701) (63) (15,248) (735) (14,453)
Extensions and discoveries ............. 522 19,166 - - 522 19,166
Production ............................. (534) (15,453) (264) (5,472) (270) (9,981)
Sale of minerals in place .............. (1,387) (23,937) (843) (9,553) (544) (14,384)
------------ ---------- ------------ ---------- ------------ ----------
Balance at December 31, 2002 (2) ......... 4,605 138,832 3,237 78,195 1,368 60,637
============ ========== ============ ========== =========== ==========
</Table>
(1) The beginning of year 2000 amounts exclude the Company's proportional
interest in Partnership proved reserves, accounted for by the equity
method, of 2.8 Mbbls of liquid hydrocarbons and 25.8 MMcf of natural gas.
(2) Includes 1,146 Bbl of liquid hydrocarbons and 47,066 Mcf of natural gas
applicable to Canadian Abraxas and Old Grey Wolf that were sold in January
2003.
F-38
<Page>
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES (CONTINUED)
<Table>
<Caption>
TOTAL UNITED STATES
------------------------------------------------------------------
LIQUID NATURAL LIQUID NATURAL
HYDROCARBONS GAS HYDROCARBONS GAS
------------------ -------------- ---------------- -------------
(BARRELS) (MCF) (BARRELS) (MCF)
(In Thousands)
PROVED DEVELOPED RESERVES:
December 31, 2000....................... 7,001 119,737 4,609 48,177
================== ============== ================ =============
December 31, 2001 ...................... 5,047 111,243 2,892 40,514
================== ============== ================ =============
December 31, 2002....................... 3,004 90,374 1,754 34,776
================== ============== ================ =============
<Caption>
CANADA
---------------------------------
LIQUID NATURAL
HYDROCARBONS GAS
------------------ --------------
(BARRELS) (MCF)
(In Thousands)
PROVED DEVELOPED RESERVES:
December 31, 2000....................... 2,392 71,560
================== =============
December 31, 2001 ...................... 2,155 70,729
================== =============
December 31, 2002....................... 1,250 55,598
================== =============
</Table>
F-39
<Page>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas are presented in accordance
with SFAS No. 69. The standardized measure does not purport to represent the
fair market value of the Company's proved crude oil and natural gas reserves. An
estimate of fair market value would also take into account, among other factors,
the recovery of reserves not classified as proved, anticipated future changes in
prices and costs, and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 2002 adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the tax basis of the properties. Operating
loss carryforwards, tax credits, and permanent differences to the extent
estimated to be available in the future were also considered in the future
income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
Set forth below is the Standardized Measure relating to proved oil and
gas reserves for:
<Table>
<Caption>
YEARS ENDED DECEMBER 31
-------------------------------------------- --------------------------------------------
2000 2001
-------------------------------------------- --------------------------------------------
TOTAL U.S. CANADA TOTAL U.S. CANADA
------------ ------------ ------------ ------------ ------------ ------------
(In thousands)
Future cash inflows ........ $ 2,046,039 $ 1,274,871 $ 771,168 $ 607,375 $ 313,640 $ 293,735
Future production and
development costs ........ (318,130) (254,667) (63,463) (220,613) (138,296) (82,317)
Future income tax expense .. (230,987) (65,421) (165,566) - - -
------------ ------------ ------------ ------------ ------------ ------------
Future net cash flows ...... 1,496,922 954,783 542,139 386,762 175,344 211,418
Discount ................... (721,388) (468,663) (252,725) (177,096) (98,157) (78,939)
------------ ------------ ------------ ------------ ------------ ------------
Standardized Measure of
discounted future net
cash relating to proved
reserves ................. $ 775,534 $ 486,120 $ 289,414 $ 209,666 $ 77,187 $ 132,479
============ ============ ============ ============ ============ ============
<Caption>
YEARS ENDED DECEMBER 31
--------------------------------------------
2002
--------------------------------------------
TOTAL U.S. CANADA
--------------------------------------------
(In thousands)
Future cash inflows ........ $ 686,055 $ 389,061 $ 296,994
Future production and
development costs ........ (225,068) (158,507) (66,561)
Future income tax expense .. - - -
------------ ------------ ------------
Future net cash flows ...... 460,987 230,554 230,433
Discount ................... (206,134) (120,238) (85,896)
------------ ------------ ------------
Standardized Measure of
discounted future net
cash relating to proved
reserves ................. $ 254,853 $ 110,316 $ 144,537
============ ============ ============
</Table>
F-40
<Page>
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
The following is an analysis of the changes in the Standardized Measure:
<Table>
<Caption>
YEAR ENDED DECEMBER 31
--------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands)
Standardized Measure, beginning
of year ........................................ $ 238,451 $ 775,534 $ 209,666
Sales and transfers of oil and gas
produced, net of production costs .............. (54,190) (54,585) (35,622)
Net changes in prices and development
and production costs from prior year ........... 707,755 (613,325) 111,087
Extensions, discoveries, and improved
recovery, less related costs ................... 290,283 39,982 46,803
Purchases of minerals in place ................... 33,586 - -
Sales of minerals in place ....................... (75,391) (96,096) (33,808)
Revision of previous quantity estimates .......... (95,757) (2,474) (36,007)
Change in future income tax expense .............. (224,668) 230,987 -
Other ............................................ (68,380) (147,910) (28,232)
Accretion of discount ............................ 23,845 77,553 20,966
---------- ---------- ----------
Standardized Measure, end of year .............. $ 775,534 $ 209,666 $ 254,853
========== ========== ==========
</Table>
F-41
<Page>
20. RESTATEMENT
In January 2003, the Company sold its wholly owned Canadian
subsidiaries, Old Grey Wolf and Canadian Abraxas as part of a series of
transactions related to a financial restructuring - see Note 2 for
additional information regarding an exchange offer, redemption of certain
notes and a new credit agreement. Subsequent to the issuance of its
consolidated financial statements for the year ended December 31, 2002, the
Company's management determined that the wholly owned Canadian subsidiaries
should not have been presented as discontinued operations. As a result, the
accompanying consolidated balance sheets as of December 31, 2002 and 2001,
and the related consolidated statements of operations, and cash flows for
each of the three years in the period ended December 31, 2002 have been
restated to present the assets and liabilities, results of operations, and
cash flows as components of continuing operations.
A summary of the significant effects of the restatement is as follows (In
thousands):
<Table>
<Caption>
FOR THE YEAR ENDED DECEMBER 31,
2000 2001 2002
--------------------------------------------------------------------------------
AS AS AS
PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
---------- ---------- ---------- ---------- ---------- ----------
Revenues:
Oil and gas production revenue $ 32,165 $ 72,973 $ 34,934 $ 73,201 $ 21,601 $ 50,862
Gas processing revenue - 2,717 - 2,438 - 2,420
Rig revenue 505 505 756 756 635 635
Other 216 405 85 848 71 403
---------- ---------- ---------- ---------- ---------- ----------
32,886 76,600 35,775 77,243 22,307 54,320
Operating costs and expenses:
Lease operating and production taxes 7,755 18,783 9,302 18,616 7,910 15,240
Depreciation, depletion and amortization 12,328 35,857 12,336 32,484 9,654 26,539
Proved property impairment - - - 2,638 32,850 115,993
Rig operations 717 717 702 702 567 567
General and administrative 4,840 6,533 4,937 6,445 5,082 6,884
General and
administrative(Stock-based compensation) 2,767 2,767 (2,767) (2,767) - -
---------- ---------- ---------- ---------- ---------- ----------
28,407 64,657 24,510 58,118 56,063 165,223
---------- ---------- ---------- ---------- ---------- ----------
Operating income (loss) 4,479 11,943 11,265 19,125 (33,756) (110,903)
Other (income) expense:
Interest income (530) (530) (78) (78) (92) (92)
Amortization of deferred financing fees 1,660 2,091 1,907 2,268 1,325 2,095
Interest expense 22,847 31,140 23,922 31,523 24,689 34,150
Financing costs - - - - 967 967
(Gain) loss on sale of equity investment (33,983) (33,983) 845 845 - -
Gain on debt extinguishment (1) - (1,773) - - - -
Other (b) 1,116) 1,563 207 207 201 201
---------- ---------- ---------- ---------- ---------- ----------
(8,890) (1,492) 26,803 34,765 27,090 37,321
---------- ---------- ---------- ---------- ---------- ----------
Income (loss) before income tax 13,369 13,435 (15,538) (15,640) (60,846) (148,224)
Income tax expense (benefit):
Current - (1,233) 505 505 - -
Deferred 3,433 4,938 - 1,897 - (29,697)
Minority interest in income of consolidated
foreign subsidiary - 1,281 - 1,676 - -
Loss from discontinued operations (3,260) - (3,675) - (57,681) -
Extraordinary item: gain on debt
extinguishment (1) 1,773 -
---------- ---------- ---------- ---------- ---------- ----------
Net income (loss) $ 8,449 $ 8,449 $ (19,718) $ (19,718) $ (118,527) $ (118,527)
========== ========== ========== ========== ========== ==========
</Table>
F-42
<Page>
(1) As required by SFAS No. 145, the Company has reclassified the gain
on the early extinguishment of debt in 2000 originally reported as an
extraordinary item to other income. See Note 1.
<Table>
<Caption>
DECEMBER 31
-------------------------------------------------------------
2001 2002
----------------------------- -----------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ------------- ------------- -------------
CURRENT ASSETS:
Cash $ 3,593 $ 7,605 $ 557 $ 4,882
Accounts receivable:
Joint owners 938 2,785 516 2,215
Oil and gas production sales 2,988 4,758 5,292 7,466
Other 135 504 221 364
------------- ------------- ------------- -------------
4,061 8,047 6,029 10,045
Equipment inventory 1,061 1,251 1,021 1,014
Other current assets 250 443 316 1,240
------------- ------------- ------------- -------------
8,965 17,346 7,923 17,181
Assets held for sale 163,902 - 74,247 -
------------- ------------- ------------- -------------
Total current assets 172,867 17,346 82,170 17,181
Property and equipment:
Oil and gas properties:
Proved 290,635 486,098 298,972 521,995
Unproved 4,571 10,626 7,052 7,052
Other property and equipment 2,587 67,632 2,713 44,189
------------- ------------- ------------- -------------
Total 297,793 564,356 308,737 573,236
Less accumulated depreciation,
depletion and amortization 170,307 282,462 212,811 422,842
------------- ------------- ------------- -------------
Total property and equipment - net 127,486 281,894 95,926 150,394
Deferred financing fees 2,779 3,928 2,970 5,671
Deferred income taxes - - - 7,820
Other 484 448 359 359
------------- ------------- ------------- -------------
Total assets $ 303,616 $ 303,616 $ 181,425 $ 181,425
============= ============= ============= =============
Current Liabilities:
Accounts payable $ (a) 3,8622 $ 10,542 $ 4,171 $ 9,687
Joint interest oil and gas production payable 1,180 3,596 1,637 2,432
Accrued interest 5,000 6,013 5,000 6,009
Other accrued expenses 1,052 1,116 1,162 1,162
Hedge liability 438 658 - -
Current maturities of long-term debt 415 415 63,500 63,500
------------- ------------- ------------- -------------
11,947 22,340 75,470 82,790
Liabilities related to assets held for sale 57,552 - 56,697 -
------------- ------------- ------------- -------------
Total current liabilities 69,499 22,340 132,167 82,790
Long-term debt 262,240 285,184 190,979 236,943
Deferred income taxes - 20,621 - -
Future site restoration 462 4,056 533 3,946
Stockholders' equity (deficit) (28,585) (28,585) (142,254) (142,254)
------------- ------------- ------------- -------------
Total liabilities and stockholders' deficit $ 303,616 $ 303,616 $ 181,425 $ 181,425
============= ============= ============= =============
</Table>
(a) Previously reported as $5,042 due to clerical error. Amount has been
corrected.
(b) Previously reported as $1,016 due to clerical error. Amount has been
corrected.
************************************************************************
F-43
<Page>
ABRAXAS PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<Table>
<Caption>
MARCH 31, DECEMBER 31,
2003 2002
(AS RESTATED, SEE NOTE 13)
(UNAUDITED)
------------ ------------
ASSETS:
Current assets:
Cash .................................................... $ 2,510 $ 4,882
Accounts receivable, net:
Joint owners ..................................... 950 2,215
Oil and gas production ........................... 5,289 7,466
Other ............................................ 561 364
------------ ------------
6,800 10,045
Equipment inventory ...................................... 698 1,014
Other current assets ..................................... 1,026 1,240
------------ ------------
Total current assets ................................... 11,034 17,181
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ................................................. 305,320 521,995
Unproved, not subject to amortization .................. 7,052 7,052
Other property and equipment ............................ 2,987 44,189
------------ ------------
Total .............................................. 315,359 573,236
Less accumulated depreciation, depletion, and
amortization ....................................... 214,400 422,842
------------ ------------
Total property and equipment - net ................... 100,959 150,394
Deferred financing fees, net ............................... 5,317 5,671
Deferred income taxes ...................................... 7,820
Other assets ............................................... 364 359
------------ ------------
Total assets ............................................. $ 117,674 $ 181,425
============ ============
</Table>
See accompanying notes to consolidated financial statements
F-44
<Page>
ABRAXAS PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(IN THOUSANDS)
<Table>
<Caption>
MARCH 31, DECEMBER 31,
2003 2002
(AS RESTATED, SEE NOTE 13)
(UNAUDITED)
------------ ------------
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable ......................................... $ 5,186 $ 9,687
Oil and gas production payable ........................... 2,549 2,432
Accrued interest ......................................... 2,457 6,009
Other accrued expenses ................................... 2,711 1,162
Current maturities of long-term debt ..................... - 63,500
------------ ------------
Total current liabilities .............................. 12,903 82,790
Long-term debt ............................................. 173,735 236,943
Future site restoration .................................... 1,237 3,946
Stockholders'deficit:
Common Stock, par value $.01 per share-
authorized 200,000,000 shares; issued, 35,795,998 and
30,145,280 in 2003 and 2002 respectively ............... 358 301
Additional paid-in capital ............................... 140,595 136,830
Receivable from stock sale ............................... (97) (97)
Accumulated deficit ...................................... (206,919) (269,621)
Treasury stock, at cost, 165,883 shares .................. (964) (964)
Accumulated other comprehensive loss ..................... (3,174) (8,703)
------------ ------------
Total stockholders' deficit .......................... (70,201) (142,254)
------------ ------------
Total liabilities and stockholders' deficit ................ $ 117,674 $ 181,425
============ ============
</Table>
See accompanying notes to consolidated financial statements
F-45
<Page>
ABRAXAS PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS EXCEPT PER SHARE DATA)
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31,
----------------------------
2003 2002
----------------------------
(AS RESTATED, SEE NOTE 13)
----------------------------
Revenue:
Oil and gas production revenues ......................... $ 12,772 $ 10,886
Gas processing revenue .................................. 132 670
Rig revenues ............................................ 181 151
Other ................................................... 226 100
------------ ------------
13,111 11,807
Operating costs and expenses:
Lease operating and production taxes .................... 2,726 3,909
Depreciation, depletion and amortization ................ 3,142 6,814
Rig operations .......................................... 166 121
General and administrative .............................. 1,395 1,698
General and administrative (stock-based compensation) ... 36 -
------------ ------------
7,465 12,542
------------ ------------
Operating income (loss) .................................... 5,646 (735)
Other (income) expense
Interest income ......................................... (10) (33)
Interest expense ........................................ 5,164 8,413
Amortization of deferred financing fees ................. 377 427
Financing cost .......................................... 3,601 -
Gain on sale of foreign subsidiaries .................... (66,960) -
------------ ------------
(57,828) 8,807
------------ ------------
Earnings (loss) before cumulative effect of
accounting change and taxes ............................. 63,474 (9,542)
------------ ------------
Cumulative effect of accounting change ..................... (395) -
------------ ------------
Earnings (loss) before taxes ............................... 63,079 (9,542)
Income tax expense (benefit) ............................... $ 377 $ (843)
------------ ------------
Net earnings (loss) ........................................ $ 62,702 (8,699)
============ ============
Basic earnings (loss) per common share:
Net earnings (loss) ..................................... $ 1.84 $ (0.29)
Cumulative effect of accounting change .................. (0.01) -
------------ ------------
Net earnings (loss) per common - basic ..................... $ 1.83 $ (0.29)
============ ============
Diluted earnings (loss) per common share:
Net earnings (loss) ..................................... $ 1.83 $ (0.29)
Cumulative effect of accounting change .................. (0.01) -
------------ ------------
Net earnings (loss) per common share - diluted ............. $ 1.82 $ (0.29)
============ ============
</Table>
See accompanying notes to consolidated financial statements
F-46
<Page>
ABRAXAS PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31,
----------------------------
2003 2002
----------------------------
(AS RESTATED, SEE NOTE 13)
----------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) ......................................... $ 62,702 $ (8,699)
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization .................. 3,142 6,814
Deferred income tax expense (benefit) ...................... 377 (843)
Amortization of deferred financing fees .................... 377 427
Amortization of debt discount .............................. - 113
Stock-based compensation ................................... 36 -
Gain on sale of foreign subsidiaries ....................... (66,960) -
Changes in operating assets and liabilities:
Accounts receivable ................................... (1,160) 1,099
Equipment inventory ................................... 162 91
Other ................................................. 1,650 (87)
Accounts payable and accrued expenses ................. 2,419 9,367
------------ ------------
Net cash provided by operations ............................ 2,745 8,282
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ............................ (4,589) (17,408)
Proceeds from sale of foreign subsidiaries ................. 85,824
------------ ------------
Net cash provided by (used) in investing activities ........ $ 81,235 $ (17,408)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term borrowings ......................... 43,189 6,096
Payments on long-term borrowings ........................... (130,903) (719)
Issuance of common stock in connection with exchange ....... 3,651 -
Exercise of stock options .................................. 5 -
Deferred financing fees .................................... (2,529) -
------------ ------------
Net cash (used) in provided by financing activities ........ (86,587) 5,377
------------ ------------
Effect of exchange rate changes on cash .................... 235 (5)
------------ ------------
Increase (decrease) in cash ................................ (2,372) (3,754)
Cash, at beginning of period ............................... 4,882 7,605
------------ ------------
Cash, at end of period ..................................... $ 2,510 $ 3,851
============ ============
Supplemental disclosures of cash flow information:
Interest paid .............................................. $ 3,029 $ 4,935
============ ============
</Table>
See accompanying notes to consolidated financial statements
F-47
<Page>
ABRAXAS PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(tabular amounts in thousands except per share data)
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. 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 financial position and
results of operations. Any and all adjustments are of a normal and recurring
nature. The results of operations for the three months ended March 31, 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 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.
During 2002, crude oil and natural gas prices began to increase from 2001 levels
and increased further in the first quarter of 2003. In addition, because 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, its
reserves and production will decrease. 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, exploitation, exploration and
development projects. In order to provide liquidity and capital resources, the
Company has sold certain of its producing properties. However, production levels
have declined as the Company has been unable to replace the production
represented by the properties sold with new production from the producing
properties it has invested in with the proceeds of property sales. In addition,
under the terms of its new senior credit agreement and New Notes, 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.
Certain prior years balances have been reclassified for comparative
purposes.
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.
For the period ended March 31, 2002, no tax provision was required due to
operating losses. For the period ended March 31, 2003, no current taxes have
been provided due to operating losses for tax purposes resulting from, among
other items, differing book and tax basis of assets sold. Deferred tax expense
of $377,000 related to Canadian operations for the period ended March 31, 2003
has been provided for.
NOTE 3. RECENT EVENTS
F-48
<Page>
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
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
such notes tendered in the exchange offer, tendering note holders received:
- cash in the amount of $264;
- an 11 1/2% Secured Note due 2007, Series A ("New Notes"), with
a principal amount equal to $610; and
- 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately $190.1
million of the Second Lien Notes and $800,000 of the Old Notes outstanding.
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, for approximately $11.5 million ($11.1
million in principal and $0.4 million in interest). The indentures for the
Second Lien Notes and Old Notes have been duly discharged. In connection with
the exchange offer, Abraxas made cash payments of approximately $47.5 million
and issued approximately $109.7 million in principal amount of New Notes and
5,642,699 shares of Abraxas common stock. Fees and expenses incurred in
connection with the exchange offer were approximately $3.8 million
REDEMPTION OF FIRST LIEN NOTES. On January 24, 2003, the Company
completed the redemption of 100% of its outstanding 12?% Senior Secured Notes,
Series B ("First Lien Notes"), with approximately $66.4 million of the proceeds
from the sale of Canadian Abraxas and Old Grey Wolf. Prior to the redemption,
the Company had $63.5 million of its First Lien Notes outstanding. Under the
terms of the indenture for the First Lien Notes, the Company had the right to
redeem the First Lien Notes at 100% of the outstanding principal amount of the
notes, plus accrued and unpaid interest to the date of redemption, and to
discharge the indenture upon call of the First Lien Notes for redemption and
deposit of the redemption funds with the trustee. The Company exercised these
rights on January 23, 2003 and upon the discharge of the indenture, the trustee
released the collateral securing the Company's obligations under the First Lien
Notes.
NOTE 4. LONG-TERM DEBT
Long-term debt consisted of the following:
<Table>
<Caption>
MARCH 31 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") ................. 128,598 -
Senior Secured Credit Agreement ............................ 45,137 -
------------ ------------
173,735 300,443
Less current maturities .................................... - 63,500
------------ ------------
$ 173,735 $ 236,943
============ ============
</Table>
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, Series A, 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
F-49
<Page>
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 Corporation, Sandia Operating Corp. (a wholly-owned subsidiary of Sandia Oil
& Gas), Wamsutter Holdings, Inc., New Grey Wolf, Western Associated Energy
Corporation and Eastside Coal Company, Inc. 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
- are subordinated to the indebtedness under the new senior
credit agreement;
- rank equally with all of Abraxas' current and future senior
indebtedness; and
- 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:
<Table>
<Caption>
PERIOD PERCENTAGE
- ------ ----------
From January 24, 2003 to June 23, 2003...................... 80.0429%
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%
</Table>
Under the indenture, the Company is subject to customary covenants which, among
other things, restricts our ability to:
- borrow money or issue preferred stock;
- pay dividends on stock or purchase stock;
- make other asset transfers;
- transact business with affiliates;
- sell stock of subsidiaries;
- engage in any new line of business;
- impair the security interest in any collateral for the notes;
- use assets as security in other transactions; and
- 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
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
F-50
<Page>
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 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 $49.9 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. 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. As of March 31, 2003,
the balance of the facility was $40.9 million. We plan to use the remaining
borrowing availability under the new senior credit agreement to fund our
operations, including capital expenditures.
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 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:
- incur additional indebtedness;
- create or permit to be created any liens on any of our
properties;
- enter into any change of control transactions;
- dispose of our assets;
- change our name or the nature of our business;
- make any guarantees with respect to the obligations of third
parties;
- enter into any forward sales contracts;
- make any payments in connection with distributions, dividends
or redemptions relating to our outstanding securities; or
- 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 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 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 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.
F-51
<Page>
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. The Company
recognized approximately $36,000 in expense during the quarter ended March 31,
2003 as General and administrative (stock-based compensation) in the
accompanying consolidated financial statements.
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
quarters ended March 31, 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 months ended March 31, 2003 and March 31,
2002 would have been:
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31,
----------------------------
2003 2002
------------ -------------
Net income (loss) as reported ............................ $ 62,702 $ (8,699)
Add: Stock-based employee compensation expense
included in reported net income, net of related
tax effects ......................................... 36 -
------------ -------------
Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all awards,
net of related tax effects .......................... (67) (72)
------------ -------------
Pro forma net income (loss) .............................. $ 62,671 $ (8,771)
============ =============
Earnings (loss) per share:
Basic - as reported ................................... $ 1.84 $ (0.29)
============ =============
Basic - pro forma ..................................... $ 1.84 $ (0.30)
============ =============
Diluted - as reported ................................. $ 1.83 $ (0.29)
============ =============
Diluted - pro forma ................................... $ 1.82 $ (0.30)
============ =============
</Table>
F-52
<Page>
NOTE 6. EARNINGS (LOSS) PER SHARE
The following table sets forth the computation of basic and diluted
earnings per share:
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31,
-----------------------------
2003 2002
------------- -------------
Numerator:
Numerator for basic and diluted earnings per share
Net earnings (loss) before cumulative effect of accounting change (in
thousands) ......................................................... $ 63,097) $ (8,699)
Cumulative effect of accounting change .................................. (395) -
------------- -------------
Numerator for basic and diluted earnings per share
Net earnings (loss) available to common stockholders (in thousands) .... 62,702 (8,699)
============= =============
Denominator:
Denominator for basic earnings per share - weighted-average shares .... 34,181,118 29,979,397
Effect of dilutive securities:
Stock options and Warrants ......................................... 319,472 -
------------- -------------
Denominator for diluted earnings per share - adjusted weighted-average
shares and assumed Conversions ..................................... 34,500,590 29,979,397
============= =============
Basic earnings (loss) per share:
Net earnings (loss) before cumulative effect of accounting change ... $ 1.84 $ (0.29)
Cumulative effect of accounting change .............................. (0.01) -
------------- -------------
Net earnings (loss) per common share - basic ............................ $ 1.83 $ (0.29)
============= =============
Diluted earnings (loss) per share:
Net earnings (loss) before cumulative effect of accounting change .. $ 1.83 $ (0.29)
Cumulative effect of accounting change .............................. (0.01) -
------------- -------------
Net earnings (loss) per common share - diluted .......................... $ 1.82 $ (0.29)
============= =============
</Table>
For the three months ended March 31, 2002, 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 this period, dilutive shares would have
been 45,982 shares for the three months ended March 31, 2002.
NOTE 7. 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". Under SFAS 133, all derivative
instruments are recorded on the balance sheet at fair value. If the derivative
does not qualify as a hedge or is not designated as a hedge, the gain or loss on
the derivative is recognized currently in earnings. To qualify for hedge
accounting, the derivative must qualify either as a fair value hedge, cash flow
hedge or foreign currency hedge. Currently, the Company uses only cash flow
hedges and the remaining discussion will relate exclusively to this type of
derivative instrument. If the derivative qualifies for hedge accounting, the
gain or loss on the derivative is deferred in Other Comprehensive Income (Loss),
a component of Stockholders' Equity, to the extent that the hedge is effective.
The relationship between the hedging instrument and the hedged item must
be highly effective in achieving the offset of changes in cash flows
attributable to the hedged risk both at the inception of the contract and on an
ongoing basis. Hedge accounting is discontinued prospectively when a hedge
instrument becomes ineffective. Gains and losses deferred in accumulated Other
Comprehensive Income (Loss) related to a cash flow hedge that becomes
ineffective remain unchanged until the related production is delivered. If the
Company determines that it is probable that a hedged transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
F-53
<Page>
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 calendar 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 calendar months of March 2003 through
February 2004.
The following table sets forth the Company's hedge position as of March
31, 2003:
<Table>
<Caption>
Time Period Notional Quantities Price Fair Value
--------------------------------- ------------------------- ------------------------------ ----------
February 1, 2003--July 31, 2003 5,000 MMBtu of production Collar with floor of $4.00 and $ -
per day ceiling of $6.25
March 1, 2003 - February 29, 2004 5,000 MMBtu of production Floor of $4.50 $ 361,769
per day
</Table>
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 March 31, 2003, a
commodity price increase of 10% would have resulted in an unfavorable change in
the fair market value of $36,200 and a commodity price decrease of 10% would
have resulted in a favorable change in fair market value of $36,200.
NOTE 8. CONTINGENCIES
LITIGATION - In 2001 the Company and a limited partnership, of which
Wamsutter Holdings, 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 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
interest in the judgment.
In late 2000, the Company received a Final De Minimis Settlement Offer from
the United States Environmental Protection Agency concerning the Casmalia
Disposal Site, Santa Barbara County, California. The Company's liability for the
cleanup at the Superfund site is based on its acquisition of Bennett Petroleum
Corporation, which is alleged to have transported or arranged for the
transportation of oil field waste and drilling muds to the Superfund site. The
Company has engaged California counsel to evaluate the notice of proposed de
minimis settlement and its notice of potential strict liability under the
Comprehensive Environmental Response, Compensation and Liability Act. Defense of
the action is handled through a joint group of companies, all of which are
claiming a petroleum exclusion that limits the Company's liability. The
potential financial exposure and any settlement posture has yet not been
developed, but is considered by the Company to be immaterial.
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 March 31, 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 9. COMPREHENSIVE INCOME
Comprehensive income includes net income (losses) and certain items recorded
directly to Stockholders' Deficit and classified as Other Comprehensive Income.
The following table illustrates the calculation of comprehensive income
(loss) for the quarter ended March 31, 2003:
F-54
<Page>
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31
2003 2002
---------------------------
Net income ................................................. $ 62,702 $ (8,699)
Other Comprehensive income:
Hedging derivatives (net of tax) - See Note 7
Change in fair market value of
outstanding hedge positions ........................... 102 (2,075)
Foreign currency translation adjustment ................. 5,427 (367)
------------ ------------
Other comprehensive income ................................. 5,529 (2,442)
------------ ------------
Comprehensive income ....................................... $ 68,231 $ (11,141)
============ ============
</Table>
NOTE 10. BUSINESS SEGMENTS
Business segment information about our first quarter operations in different
geographic areas is as follows:
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31, 2003
-------------------------------------
U.S. CANADA TOTAL
---------- ---------- ----------
(In thousands)
Revenues ................................$ 8,799 $ 4,312 $ 13,111
========== ========== ==========
Operating profit ........................$ 4,736 $ 2,243 $ 6,979
========== ==========
General corporate ....................... (1,333)
Interest expense and amortization of
deferred financing fees .............. (9,132)
Gain on sale of foreign subsidiary ... .. 66,960
Cumulative effect of accounting change... (395)
----------
Income before income taxes ........... $ 63,079
==========
Identifiable assets at March 31, 2003....$ 82,179 $ 29,060 $ 111,239
========== ==========
Corporate assets ........................ 6,435
----------
Total assets ......................... $ 117,764
==========
</Table>
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31, 2003
-------------------------------------
U.S. CANADA TOTAL
---------- ---------- ----------
(In thousands)
Revenues ................................$ 4,616 $ 7,191 $ 11,807
========== ========== ==========
Operating profit ........................$ 454 $ (199) $ 255
========== ========== ==========
General corporate ....................... (990)
Interest expense and amortization of
deferred financing fees .............. (8,807)
----------
Income before income taxes ........... $ (9,542)
==========
</Table>
NOTE 11. NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the purchase method of
accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. Intangible assets with a determinable
useful life will continue to be amortized over that period. The amortization
provisions apply to goodwill and intangible assets acquired after June 30, 2001.
SFAS No. 141 and 142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did not change or
reclassify contractual mineral rights included in oil and gas properties on the
balance sheet upon adoption of SFAS No. 142. The Company believes the treatment
of such mineral rights as tangible assets under the full cost method of
accounting for crude oil and natural gas properties is appropriate. An issue has
arisen regarding whether contractual mineral rights should be classified as
intangible rather that
F-55
<Page>
tangible assets. If it is determined that reclassification is necessary, the
Company's oil and gas properties would be reduced by $3.1 million and intangible
assets would have increased by a like amount at March 30, 2003 and December 31,
2002, representing cost incurred from the effective date of June 30, 2001. The
provisions of SFAS No. 141 and 142 impact only the balance sheet and associated
footnote disclosure, and reclassifications necessary would not impact the
Company's cash flow or results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting
for obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. SFAS 143 is effective for us January 1,
2003. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortize these costs as a component of our depletion
expense in the accompanying consolidated financial statements.
The Company adopted SFAS 143 effective January 1, 2003. For the quarter
ended March 31, 2003 the Company recorded an additional liability of $711,732, a
charge of $395,341 for the cumulative effect of the change in accounting
principal and current expense of $19,108.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1,
2002, the Company adopted SFAS No. 144. SFAS No. 144 retains the requirement to
recognize an impairment loss only where the carrying value of a long-lived asset
is not recoverable from its undiscounted cash flows and to measure such loss as
the difference between the carrying amount and fair value of the asset. SFAS No.
144, among other things, changes the criteria that have to be met to classify an
asset as held-for-sale and requires that operating losses from discontinued
operations be recognized in the period that the losses are incurred rather than
as of the measurement date. This new standard had no impact on the Company's
consolidated financial statements during the first quarter of 2003.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4,
44, and 64, Amendments of FASB Statement No. 13 and Technical Corrections" (SFAS
145). SFAS 145 clarifies guidance related to the reporting of gains and losses
from extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS 145 also amends other
existing pronouncements to make various technical corrections, clarify meanings
or describe their applicability under changed conditions. The provisions
relating to the reporting of gains and losses from extinguishment of debt were
effective for us beginning January 1, 2003. All other provisions of this
standard have been effective for the Company as of May 15, 2002 and did not have
a significant impact on the Company's financial condition or results of
operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. SFAS
146 was effective for us beginning January 1, 2003. For the period ended March
31, 2003 this standard had no impact on the Company's financial condition or
results of operation
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-based Compensation--Transition and Disclosure, an amendment of FASB
Statement No. 123," which amends SFAS 123 to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. It also amends the disclosure provisions
of SFAS 123 to require prominent disclosure in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results. The provisions of SFAS
148 are effective for annual financial statements for fiscal years ending after
December 15, 2002, and for financial reports containing condensed financial
statements for interim periods beginning after December 15, 2002. The Company
will continue to use APB No. 25 to account for stock based compensation, while
providing the disclosures required by SFAS 123 as amended by SFAS 148.
NOTE 12. ACCOUNTING CHANGE
The Company adopted SFAS 143 effective January 1, 2003. For the quarter
ended March 31, 2003 the Company recorded an additional liability of $711,732, a
charge of $395,341 for the cumulative effect of the change in accounting
principal and current expense of $19,108.
NOTE 13. RESTATEMENT
In January 2003, the Company sold its wholly owned Canadian subsidiaries,
Old Grey Wolf and Canadian Abraxas as part of a series of transactions related
to a financial restructuring - see Note 3 for additional information regarding
an exchange offer, redemption of certain notes and a new credit agreement.
Subsequent to the issuance of its consolidated financial statements for the year
ended December 31, 2002, it was determined that the wholly owned Canadian
subsidiaries should not have been presented as discontinued operations. As a
result, the accompanying consolidated balance sheets as of December 31, 2002,
and the related
F-56
<Page>
consolidated statements of operations, for the Quarters ended
March 31, 2002 and 2003 have been restated to present the assets and
liabilities, and results of operations as components of continuing operations.
The transactions were completed in January 2003, accordingly, no restatement of
the March 31, 2003 balance sheet was necessary.
A summary of the significant effects of the restatement is as follows (In
thousands):
<Table>
<Caption>
FOR THE THREE MONTHS ENDED MARCH 31,
-------------------------------------------------
2003 2002
----------------------- -----------------------
AS AS
PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
---------- ---------- ---------- ----------
Revenues:
Oil and gas production revenue .................... $ 9,653 $ 12,772 $ 4,461 $ 10,886
Gas processing revenue ............................ - 132 - 670
Rig revenue ....................................... 181 181 151 151
Other ............................................. 2 26 4 100
---------- ---------- ---------- ----------
9,836 13,111 4,616 11,807
Operating costs and expenses:
Lease operating and production taxes .............. 2,347 2,726 1,878 3,909
Depreciation, depletion and amortization .......... 2,350 3,142 2,253 6,814
Rig operations .................................... 166 166 121 121
General and administrative ........................ 1,230 1,395 1,093 1,698
General and administrative(Stock-based compensation) 36 36 - -
---------- ---------- ---------- ----------
6,129 7,465 5,345 12,542
---------- ---------- ---------- ----------
Operating income (loss) .............................. 3,707 5,646 (729) (735)
Other (income) expense:
Interest income ................................... (10) (10) (33) (33)
Amortization of deferred financing fees ........... 329 377 331 427
Interest expense .................................. 4,523 5,164 6,235 8,413
Financing costs ................................... 3,601 3,601 -
(Gain) loss on sale of foreign subsidiaries ....... - (66,960) - -
---------- ---------- ---------- ----------
8,443 (57,828) 6,533 8,807
---------- ---------- ---------- ----------
Income (loss) before income tax ...................... (4,736) 63,474 (7,262) (9,542)
Income tax expense (benefit): ........................ - 377 - (843)
Loss from discontinued operations:
Earnings loss from discontinued operations ........ 873 - (1,437) -
Gain of sale of foreign subsidiaries .............. 66,960 - - -
---------- ---------- ---------- ----------
Net earnings from discontinued operations ............ 67,833 - (1,437) -
Cumulative effect of accounting change ............... (395) (395) - -
---------- ---------- ---------- ----------
Net income (loss) .................................... $ 62,702 $ 62,702 $ (8,699) $ (8,699)
========== ========== ========== ==========
</Table>
F-57
<Page>
<Table>
<Caption>
DECEMBER 31, 2002
----------------------------
AS
PREVIOUSLY AS
REPORTED RESTATED
------------ ------------
Current Assets:
Cash $ 557 $ 4,882
Accounts receivable:
Joint owners 516 2,215
Oil and gas production sales 5,292 7,466
Other 221 364
------------ ------------
6,029 10,045
Equipment inventory 1,021 1,014
Other current assets 316 1,240
------------ ------------
7,923 17,181
Assets held for sale 74,247 -
------------ ------------
Total current assets 82,170 17,181
Property and equipment:
Oil and gas properties:
Proved 298,972 521,995
Unproved 7,052 7,052
Other property and equipment 2,713 44,189
------------ ------------
Total 308,737 573,236
Less accumulated depreciation, depletion
and amortization 212,811 422,842
------------ ------------
Total property and equipment - net 95,926 150,394
Deferred financing fees 2,970 5,671
Deferred income taxes - 7,820
Other 359 359
------------ ------------
Total assets $ 181,425 $ 181,425
============ ============
Current Liabilities:
Accounts payable $ 4,171 $ 9,687
Joint interest oil and gas production payable 1,637 2,432
Accrued interest 5,000 6,009
Other accrued expenses 1,162 1,162
Hedge liability - -
Current maturities of long-term debt 63,500 63,500
------------ ------------
75,470 82,790
Liabilities related to assets held for sale 56,697 -
------------ ------------
Total current liabilities 132,167 82,790
Long-term debt 190,979 236,943
Deferred income taxes - -
Future site restoration 533 3,946
Stockholders' equity (deficit) (142,254) (142,254)
------------ ------------
Total liabilities and stockholders' deficit $ 181,425 $ 181,425
============ ============
</Table>
F-58
<Page>
FINANCIAL STATEMENTS
GREY WOLF EXPLORATION INC.
DECEMBER 31, 2002
F-59
<Page>
Deloitte & Touche LLP
3000, 700 Second Street SW
Calgary AB Canada T2P 0S7
Telephone +1 403-267-1700
Facsimile +1 403-264-2871
AUDITORS' REPORT
To the Directors of
Grey Wolf Exploration Inc.
We have audited the balance sheets of Grey Wolf Exploration Inc. as at December
31, 2002 and 2001 and the statements of earnings (loss) and retained earnings
(deficit) and of cash flows for each of the years in the three year period ended
December 31, 2002. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
With respect to the financial statements for each of the years in the three-year
period ended December 31, 2002, we conducted our audits in accordance with
Canadian generally accepted auditing standards and auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2002 and 2001
and the results of its operations and its cash flows for each of the years in
the three year period ended December 31, 2002 in accordance with Canadian
generally accepted accounting principles.
On February 23, 2001, we reported separately to the shareholders of the Company
on financial statements for the year ended December 31, 2000, prepared in
accordance with the Canadian generally accepted accounting principles, which
excluded Note 12 on differences between Canadian and United States generally
accepted accounting principles.
Calgary, Canada /s/ Deloitte & Touche LLP
March 10, 2003 Chartered Accountants
F-60
<Page>
COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA - U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) outlining changes in
accounting principles that have been implemented in the financial statements. As
discussed in Note 7 to the financial statements, in 2001 the Company changed its
method of computing diluted earnings per share to conform to the new Canadian
Institute of Chartered Accountants Handbook recommendation section 3500. In
addition, as discussed in Note 6 to the financial statements, in 2000 the
Company changed its method of accounting for income taxes to conform to the new
Canadian Institute of Chartered Accountants Handbook recommendation section
3465.
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) outlining significant
subsequent events that have been disclosed in the financial statements. We have
not audited any financial statements of the Company for any period subsequent to
December 31, 2002. However, as discussed in Note 13, the Company's parent
company sold all of the outstanding common shares of the Company on January 23,
2003.
Calgary, Canada /s/ Deloitte & Touche LLP
March 10, 2003 Chartered Accountants
F-61
<Page>
GREY WOLF EXPLORATION INC.
BALANCE SHEETS
AS AT DECEMBER 31
(THOUSANDS OF CANADIAN DOLLARS)
<Table>
<Caption>
2002 2001
$ $
------------ ------------
ASSETS
CURRENT
Cash (Note 4) 3,365 4,405
Accounts receivable (Note 10) 8,230 9,980
------------ ------------
11,595 14,385
Long-term receivable (Note 10) 10,000 10,000
Property and equipment (Note 3) 23,401 71,879
Future income taxes (Note 6) 25,233 -
------------ ------------
70,229 96,264
============ ============
LIABILITIES
CURRENT
Accounts payable and accrued liabilities (Note 10) 10,078 15,183
Long-term debt (Note 4) 69,227 36,356
Future site restoration and abandonment 1,221 1,050
Future income taxes (Note 6) - 6,359
------------ ------------
80,526 58,948
------------ ------------
CONTINGENCIES (NOTE 11)
SHAREHOLDERS' EQUITY (DEFICIENCY)
Share capital (Note 5) 27,891 27,891
Retained earnings (deficit) (38,188) 9,425
------------ ------------
(10,297) 37,316
------------ ------------
70,229 96,264
============ ============
</Table>
SEE ACCOMPANYING NOTES
F-62
<Page>
GREY WOLF EXPLORATION INC.
STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS (DEFICIT) YEARS ENDED
DECEMBER 31 (THOUSANDS OF CANADIAN DOLLARS, EXCEPT FOR SHARE AMOUNTS)
<Table>
<Caption>
2002 2001 2000
$ $ $
---------- ---------- -----------
REVENUE
Petroleum and natural gas sales 33,245 30,268 26,009
Royalties, net of Alberta Royalty Tax Credit (8,237) (7,615) (5,380)
----------- ----------- -----------
25,008 22,653 20,629
----------- ----------- -----------
EXPENSES
Operating 6,032 3,844 3,462
General and administrative (Note 3) 2,367 1,278 1,384
Interest and finance charges (Note 10) 4,518 1,827 1,126
Depletion, depreciation and site restoration (Note 3) 8,003 8,364 7,924
Write down of petroleum and natural gas properties
and facilities 82,635 - -
Amortization of deferred financing fees (Note 4) 634 - -
----------- ----------- -----------
104,189 15,313 13,896
----------- ----------- -----------
Earnings (loss) before taxes (79,181) 7,340 6,733
----------- ----------- -----------
Provision for (recovery of) taxes (Note 6)
Current 24 144 61
Future (31,592) 3,061 2,732
----------- ----------- -----------
(31,568) 3,205 2,793
----------- ----------- -----------
NET EARNINGS (LOSS) (47,613) 4,135 3,940
Retained earnings, beginning of year 9,425 5,290 1,912
Adoption of income tax accounting standard change (Note 6) - - (562)
----------- ----------- -----------
RETAINED EARNINGS (DEFICIT), END OF YEAR (38,188) 9,425 5,290
=========== =========== ===========
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE (Note 7) (3.71) 0.32 0.31
=========== =========== ===========
Weighted average number of shares
Basic 12,841,327 12,776,407 12,660,528
Diluted 12,841,327 12,776,407 12,732,251
=========== =========== ===========
</Table>
SEE ACCOMPANYING NOTES
F-63
<Page>
GREY WOLF EXPLORATION INC.
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT FOR SHARE AMOUNTS)
<Table>
<Caption>
2002 2001 2000
$ $ $
---------- ---------- ----------
OPERATING ACTIVITIES
Net earnings (loss) (47,613) 4,135 3,940
Depletion, depreciation and site restoration 8,003 8,364 7,924
Write down of petroleum and natural gas properties and facilities 82,635 - -
Future income tax expense (recovery) (31,592) 3,061 2,732
Amortization of deferred financing fees 634 - -
---------- ---------- ----------
Cash flow from operations 12,067 15,560 14,596
Changes in non-cash working capital items (Note 9) (3,355) (746) 1,936
---------- ---------- ----------
8,712 14,814 16,532
---------- ---------- ----------
FINANCING ACTIVITIES
Increase in long-term debt 67,994 28,334 (273)
Repayments of long-term debt (35,723) - -
Increase in long-term receivable - (10,000) -
Issuance of common shares - 336 3
---------- ---------- ----------
32,271 18,670 (270)
---------- ---------- ----------
TOTAL CASH RESOURCES PROVIDED 40,983 33,484 16,262
---------- ---------- ----------
INVESTING ACTIVITIES
Property and equipment received under property swap agreement - - 10,779
Disposal of property and equipment under property swap agreement - - (12,332)
---------- ---------- ----------
Net cash proceeds - - (1,553)
Other acquisitions - 1,071 13
Expenditures for property and equipment 45,558 36,800 17,941
Dispositions of property and equipment (3,657) (8,838) (342)
Site restoration 122 46 203
---------- ---------- ----------
42,023 29,079 16,262
---------- ---------- ----------
INCREASE (DECREASE) IN CASH (1,040) 4,405 -
Cash, beginning of year 4,405 - -
---------- ---------- ----------
CASH, END OF YEAR 3,365 4,405 -
========== ========== ==========
BASIC AND DILUTED CASH FLOW FROM OPERATIONS
PER SHARE (Note 7) 0.94 1.22 1.15
========== ========== ==========
Cash interest paid 5,483 1,840 1,123
Cash taxes paid 88 82 72
========== ========== ==========
</Table>
SEE ACCOMPANYING NOTES
F-64
<Page>
GREY WOLF EXPLORATION INC.
NOTES TO THE FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT FOR SHARE AMOUNTS)
1. DESCRIPTION OF BUSINESS
Grey Wolf Exploration Inc. ("Grey Wolf" or "the Company") was incorporated
under the laws of the Province of Alberta on December 23, 1986. The
Company's primary business is the exploration, development and production
of crude oil and natural gas in western Canada. As at December 31, 2002 and
2001 the Company was a wholly-owned subsidiary of Abraxas Petroleum
Corporation ("Abraxas").
2. SIGNIFICANT ACCOUNTING POLICIES
These financial statements have been prepared in accordance with Canadian
generally accepted accounting principles. Differences between Canadian and
U.S. GAAP are outlined in Note 12 to the financial statements.
CASH
Cash includes amounts held in short-term deposits with original maturities
of 90 days or less.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting in accordance with
the guideline issued by the Canadian Institute of Chartered Accountants
("CICA") whereby all costs associated with the exploration for and
development of petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre and charged to
income as set out below. Such costs include acquisition, drilling,
geological and geophysical costs related to exploration and development
activities. Costs of acquiring and evaluating unproved properties are
excluded from the depletion base until it is determined whether or not
proved reserves are attributable to the properties or impairment occurs.
Gains or losses are not recognized upon disposition of petroleum and
natural gas properties unless crediting the proceeds against accumulated
costs would result in a change in the rate of depletion of 20% or more.
Depletion of petroleum and natural gas properties and depreciation of
production equipment, except for gas plants and related facilities, is
provided on accumulated costs using the unit-of-production method based on
estimated proved petroleum and natural gas reserves, before royalties, as
determined by independent engineers. For purposes of the depletion
calculation, proven petroleum and natural gas reserves are converted to a
common unit of measure on the basis of one barrel of oil or liquids being
equal to six thousand cubic feet of natural gas. Depreciation of gas plants
and related production facilities is calculated on a straight-line basis
over an average 18-year term.
The depletion and depreciation cost base includes capitalized costs, less
costs of unproved properties, plus provision for future development costs
of proved undeveloped reserves.
F-65
<Page>
2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
PETROLEUM AND NATURAL GAS PROPERTIES (CONTINUED)
The net carrying value of the Company's petroleum and natural gas
properties is limited to an ultimate recoverable amount (the "ceiling
test"). This amount is the aggregate of estimated future net revenues from
proved reserves and the costs of unproved properties, net of impairment
allowances, less future estimated production costs, general and
administration costs, financing costs, site restoration and abandonment
costs, and income taxes. Future net revenues are estimated using period end
prices and costs without escalation or discounting, and the income tax and
Alberta Royalty Tax Credit legislation substantially enacted at the balance
sheet date.
Furniture, leasehold improvements, computer hardware, software and office
equipment are carried at cost and are depreciated over the estimated useful
life of the assets at rates varying between 20 percent and 30 percent, on a
declining-balance basis.
FUTURE SITE RESTORATION AND ABANDONMENT COSTS
The estimated cost of future site restoration is based on the current cost
and the anticipated method and extent of site restoration in accordance
with existing legislation and industry practice. The annual charge is
provided for on a unit-of-production basis for all properties except for
gas plants for which the annual charge is calculated on a straight-line
basis over the estimated remaining life of the plants. Actual site
restoration expenditures are charged to the accumulated liability account
as incurred.
USE OF ESTIMATES
The amounts recorded for depletion and depreciation of property and
equipment and the provision for site restoration are based on estimates of
proved reserves and production rates. The ceiling test calculation is based
on estimates of proved reserves, production rates, oil and natural gas
prices, future costs and other relevant assumptions. By their nature, these
estimates are subject to uncertainty and the effect on the financial
statements of changes in such estimates could be significant.
F-66
<Page>
2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
JOINT OPERATIONS
Substantially all of the Company's exploration and development activities
are conducted jointly with others, and accordingly, the financial
statements reflect only the Company's proportionate interest in such
activities.
REVENUE RECOGNITION
Petroleum and natural gas sales are recognized when the commodities are
delivered to purchasers.
FUTURE INCOME TAXES
Effective January 1, 2000, the Company adopted, on a retroactive basis
without restatement of prior periods, the new Canadian Institute of
Chartered Accountants ("CICA") accounting recommendation, "Income Taxes".
Under this standard, future income tax assets and liabilities are measured
based upon temporary differences between the carrying values of assets and
liabilities and their tax basis. Income tax expense (recovery) is computed
based on the change during the year in the future tax assets and
liabilities. Effects of changes in tax laws and tax rates are recognized
when substantially enacted. Prior to January 1, 2000, the Company followed
the deferral method of accounting for income taxes.
STOCK OPTIONS
Prior to December 31, 2001, the Company had a stock option plan as
described in Note 5. No compensation expense was recognized when the stock
options were issued. Consideration received on exercise of stock options
was credited to share capital.
PER SHARE FIGURES
Basic per share figures are calculated using the weighted average number of
common shares outstanding during the year.
Effective January 1, 2001, the Company retroactively adopted, with
restatement of prior periods, the new recommendations of CICA Handbook
Section 3500. Under the revised standard, diluted per share figures are
calculated based on the weighted average number of shares outstanding
during the year plus the additional common shares that would have been
outstanding if potentially dilutive common shares had been issued using the
treasury stock method. Prior to the adoption of the new recommendations,
diluted per share amounts were determined using the imputed earnings
method.
F-67
<Page>
2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
COMPARATIVE FIGURES
Certain of the prior years' comparative figures have been reclassified to
conform to the current year's presentation.
3. PROPERTY AND EQUIPMENT
<Table>
<Caption>
2002
-------------------------------------------
ACCUMULATED
DEPLETION AND NET BOOK
COST DEPRECIATION VALUE
$ $ $
------------ ------------ ------------
Petroleum and natural gas properties 120,727 (102,708) 18,019
Gas plants and related production facilities 21,641 (16,314) 5,327
Other assets 621 (566) 55
------------ ------------ ------------
Net property and equipment 142,989 (119,588) 23,401
============ ============ ============
</Table>
<Table>
<Caption>
2001
-------------------------------------------
ACCUMULATED
DEPLETION AND NET BOOK
COST DEPRECIATION VALUE
$ $ $
------------ ------------ ------------
Petroleum and natural gas properties 89,516 (25,649) 63,867
Gas plants and related production facilities 11,010 (3,097) 7,913
Other assets 597 (498) 99
------------ ------------ ------------
Net property and equipment 101,123 (29,244) 71,879
============ ============ ============
</Table>
For the year ended December 31, 2002, $701,000 of general and
administrative expenses were capitalized as part of property and equipment
related directly to the Company's exploration and development activities
(2001 - $402,000 and 2000 - $380,000).
As a result of the quarterly ceiling test calculation at June 30, 2002, the
Company recorded a write-down of its petroleum and natural gas properties
and facilities in the amount of $82,635,000 ($49,649,000 net of related tax
recovery). The impairment was primarily due to lower gas prices and reserve
revisions subsequent to December 31, 2001, and higher future estimated
interest costs relating to the Mirant Facility (Note 4).
F-68
<Page>
3. PROPERTY AND EQUIPMENT (CONTINUED)
Undeveloped property costs of $4,961,511 were excluded from the depletion
base for the year ended December 31, 2002 (2001 - $6,065,907 and 2000 -
$6,441,705).
Future site restoration and abandonment charges of $294,029 are included in
depletion, depreciation and site restoration expense for the year ended
December 31, 2002 (2001 - $197,987 and 2000 - $210,486).
4. LONG-TERM DEBT
Long term debt is comprised of the following:
<Table>
<Caption>
2002 2001
$ $
------- -------
Mirant Facility 72,398 40,127
Revolving term credit facility - 5,000
Cash held in trust - (5,000)
Unamortized deferred financing charges (3,171) (3,771)
------- -------
69,227 36,356
======= =======
</Table>
At December 31, 2002 and 2001, the Company had a credit facility with
Mirant Canada Energy Capital Ltd., (the "Mirant Facility") with a maximum
available limit of $150,000,000. At December 31, 2002, $72,398,000 was
drawn on this facility (2001 - $40,127,000). Of the $72,398,000 drawn,
$10,000,000 was advanced to Canaxas (2001 - $10,000,000) (Note 10). The
Company is required to pay an amount equal to monthly net cash flow from
operations less interest payments, general and administrative expenses and
approved capital expenditures. Loan advances are supported by a first
charge demand debenture in the amount of $200,000,000 together with a
debenture pledge agreement providing a first priority lien on all the
assets of the Company.
Under the Mirant Facility, loan advances bear interest at 9.5%, plus a 5%
overriding royalty which will decrease to 2.5% when certain conditions are
met. The overriding royalty granted to Mirant was treated as a disposition
of petroleum and natural gas properties in the amount of $3,600,000, with a
corresponding deferred financing charge recorded of $3,600,000, based on
the fair value at the date of disposition. This deferred charge plus
additional fees paid in 2001 and 2002 to secure the facility have been
netted against the outstanding loan balance and are being amortized over a
6-year period ending in 2007.
F-69
<Page>
4. LONG-TERM DEBT (CONTINUED)
The Mirant Facility was used to extinguish the previous revolving term
credit facility. As at December 31, 2001, all of the previous revolving
term credit facility had been repaid except for a banker's acceptance for
$5,000,000. As at December 31, 2001, equivalent cash had been placed in
trust to cover the $5,000,000 repayment, and accordingly was netted against
the loan for financial statement purposes. The remaining $5,000,000 was
repaid in January 2002.
At December 31, 2000, the Company had a revolving term credit facility with
a Canadian chartered bank with a maximum limit of $20,000,000. At December
31, 2000, $11,792,690 was drawn down against this facility. Under the
facility, loan advances bore interest at bank prime plus 1/8%, or the then
current bankers' acceptances rate plus 1 1/8%. Loan advances were supported
by a first floating charge demand debenture in the amount of $25,000,000
covering all the assets of the Company. During May 2001, the maximum limit
under the revolving term credit facility was increased to $27,000,000 and
remained at this level until replaced by the Mirant Facility in December
2001.
Effective January 1, 2002, the Emerging Issues Committee of the CICA issued
Abstract No. 122, which requires callable debt obligations to be presented
with current liabilities on the balance sheet. The maximum available amount
under the Mirant Facility may be terminated or reduced below the
outstanding amount only upon certain unanticipated events of default, and
therefore is not classified as a callable debt obligation. In addition, it
is anticipated the Company will be a net borrower due to a number of
planned capital projects over the next several years. Accordingly, the
outstanding balance has been classified as a long-term liability on the
balance sheet. The facility matures in December 2007.
Interest and financing charges for the year ended December 31, 2002
includes $5,483,000 of interest expense relating to long-term debt (2001 -
$843,000 and 2000 - $1,126,000).
F-70
<Page>
5. SHARE CAPITAL
AUTHORIZED
Unlimited number of common shares without nominal or par value.
ISSUED
<Table>
<Caption>
NUMBER OF AMOUNT
SHARES $
------------ ------------
BALANCE, JANUARY 1, 2000 12,659,741 27,552
Exercise of stock options 1,800 3
------------ ------------
BALANCE, DECEMBER 31, 2000 12,661,541 27,555
Exercise of stock options 179,786 336
------------ ------------
BALANCE, DECEMBER 31, 2001 AND 2002 12,841,327 27,891
============ ============
</Table>
STOCK OPTIONS
Prior to December 31, 2001, a maximum of 1,270,000 options to purchase
common shares were authorized for issuance under the Company's stock option
plan. The options were exercisable on a cumulative basis at 25% per year
commencing one year after the grant date and expiring in five years from
the date of grant. During the year ended December 31, 2001, all options
outstanding in the Company were cancelled and new options were issued by
Abraxas.
<Table>
<Caption>
NUMBER WEIGHTED AVERAGE
OF OPTIONS OPTION PRICE
------------ ----------------
BALANCE, JANUARY 1, 2000 1,033,715 2.84
Issued 398,376 1.60
Exercised (1,800) 1.60
Cancelled (420,262) 2.53
------------
BALANCE, DECEMBER 31, 2000 1,010,029 2.30
Exercised (179,786) 1.87
Cancelled (830,243) 2.39
------------
BALANCE, DECEMBER 31, 2001 AND 2002 -
============
</Table>
F-71
<Page>
6. PROVISION FOR TAXES
Effective January 1, 2000, the Company accounts for future income taxes
using the liability method. Prior to January 1, 2000, the Company followed
the deferral method of accounting for income taxes.
Upon adoption of the new accounting recommendation of the CICA effective
January 1, 2000, the Company recorded a future income tax liability of
$562,000 and decreased the Company's retained earnings by $562,000. Had the
new method not been adopted, 2000 net earnings would have been increased by
$88,000.
The total provision for taxes recorded differs from the tax calculated by
applying the combined statutory Canadian corporate and provincial income
tax rates as follows:
<Table>
<Caption>
2002 2001 2000
$ $ $
-------- -------- --------
Calculated income tax (recovery) expense at
42.12% (2001 - 42.62% and 2000 - 44.62%) (33,351) 3,128 3,004
Increase (decrease) in tax resulting from:
Non-deductible crown royalties and other charges 2,511 2,950 2,254
Resource allowance and related items (583) (2,757) (2,066)
Alberta Royalty Tax Credit (105) (177) (231)
Large Corporation Tax 24 144 61
Tax rate adjustment (62) (151) -
Other (2) 68 (229)
-------- -------- --------
Provision for (recovery of) taxes (31,568) 3,205 2,793
======== ======== ========
</Table>
The major components of future income tax asset (liability) at December 31,
2002 and 2001 are as follows:
<Table>
<Caption>
2002 2001
$ $
-------- --------
Property and equipment 25,522 (7,672)
Future site restoration 514 447
Share issue costs 19 117
Attributed royalty income carried forward 607 511
Resource allowance (1,357) 310
Deferred financing costs (72) (72)
------- --------
25,233 (6,359)
------- --------
</Table>
No valuation allowance has been recorded with respect to the future income
tax asset balance at December 31, 2002 based on management's assessment
that the amount is more likely than not to be realized.
F-72
<Page>
7. PER SHARE FIGURES
The treasury method of calculating per share figures was adopted
retroactively effective January 1, 2001, with restatement of prior periods.
If the imputed earnings method was utilized for the year ended December 31,
2000, diluted net earnings per share would have been $0.31 per share and
diluted cash flow from operations per share would have been $1.11. There
was no impact on 2001 diluted per share figures as a result of adopting the
new treasury method.
8. FINANCIAL INSTRUMENTS
Financial instruments of the Company consist of accounts receivable,
long-term receivable, accounts payable and accrued liabilities, and
long-term debt. As at December 31, 2002 and 2001, there were no significant
differences between the carrying amounts of these financial instruments
reported on the balance sheets and their estimated fair values.
CREDIT RISK
The majority of the Company's accounts receivable are in respect of oil and
gas operations. The Company generally extends unsecured credit to these
customers, and therefore, the collection of accounts receivable may be
affected by changes in economic or other conditions. Management believes
the risk is mitigated by the size and reputation of the companies to which
they extend credit. The Company has not previously experienced any material
credit loss in the collection of receivables.
INTEREST RATE RISK
The Company's long-term debt bears interest at a floating market rate plus
1/8%. Accordingly, the Company is subject to interest rate risk, as the
required cash flow to service the debt will fluctuate as a result of
changes in market rates.
COMMODITY PRICE RISK
The nature of the Company's operations results in exposure to fluctuations
in commodity prices. The Company from time to time employs financial
instruments to manage its exposure to commodity prices. These instruments
are not used for speculative trading purposes. Gains and losses on
commodity price hedges are included in revenues upon the sale of the
related production. The Company had not entered into any contracts as at
December 31, 2002 and 2001.
F-73
<Page>
9. SUPPLEMENTARY CASH FLOW INFORMATION
<Table>
<Caption>
2002 2001 2000
$ $ $
-------- -------- --------
Accounts receivable 1,750 (165) (5,712)
Accounts payable and accrued liabilities (5,105) (581) 7,648
-------- -------- --------
Changes in non-cash working capital items (3,355) (746) 1,936
======== ======== ========
</Table>
10. RELATED PARTY TRANSACTIONS
The Company manages the assets and operations of Canadian Abraxas Petroleum
Limited ("Canaxas") pursuant to a Management Agreement dated November 12,
1996. Canaxas is a wholly-owned subsidiary of Abraxas. As at December 31,
2002 and 2001, Abraxas owned 97.3% (2000 - 46.0%) of the common shares of
the Company and Canaxas owned 2.7% (2000 - 2.7%) of the common shares of
the Company. The aggregate common costs of operations and administration of
the Canaxas and Grey Wolf assets are shared on a pro-rata basis, based on
revenue.
During the year ended December 31, 2002, $2,967,200 was charged to Canaxas
with respect to the Management Agreement (2001 - $2,633,716 and 2000 -
$3,456,023). Abraxas also charged the Company a corporate service charge of
$885,000 for the year ended December 31, 2002 of which $480,000 was charged
out to Canaxas. For the year ended December 31, 2001, the Abraxas corporate
service charge was $849,000 (2000 - $Nil) of which $589,000 (2000 - $Nil)
was charged out to Canaxas. All amounts relating to the Abraxas corporate
service charge and the Management Agreement with Canaxas are non-interest
bearing, are not collateralized and are due on demand.
At December 31, 2002 and 2001, the Company had a long-term receivable from
Canaxas in the amount of $10,000,000 (Note 4) (2000 - $Nil). The balance
bears interest at 9.65% and has no fixed terms of repayment. Interest and
financing charges of $4,518,000 for the year ended December 31, 2002 are
net of $965,000 interest income accrued ($Nil for comparative periods
presented) related to the long-term receivable from Canaxas.
Following is a summary of amounts included in accounts receivable,
long-term receivable and accounts payable that are due from (to) related
parties as at December 31, 2002 and 2001:
F-74
<Page>
10. RELATED PARTY TRANSACTIONS (CONTINUED)
<Table>
<Caption>
2002 2001
$ $
------------ ------------
Short-term receivable from Canaxas 1,236 4,330
Long-term receivable from Canaxas 10,000 10,000
Short-term payable to Abraxas - (849)
</Table>
11. CONTINGENCIES
The Company is subject to various claims arising from its operations in the
normal course of business, none of which are expected, individually or in
the aggregate, to have a material adverse impact on the Company's
operations or financial position.
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
RECONCILIATION TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The financial statements of the Company have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP"),
which in most respects, conform to accounting principles generally accepted
in the United States of America ("U.S. GAAP"). Differences from U.S. GAAP
having a significant effect on the Company's balance sheets and statements
of earnings (loss) and retained earnings (deficit) and of cash flows are
described and quantified below for the years indicated:
(a) Under U.S. GAAP, interest costs associated with certain capital
expenditures are required to be capitalized as part of the historical
cost of the oil and gas assets. Under Canadian GAAP, the calculation
of interest costs eligible for capitalization differs from the
calculation under U.S. GAAP in certain respects and is optional at the
discretion of the entity. Accordingly, no amounts have been
capitalized with respect to the Canadian GAAP financial statements.
The impact of recording capitalized interest under U.S. GAAP would be
to increase the carrying value of property and equipment by $168,000
in 2002, $119,000 in 2001 and $69,000 in 2000 with a corresponding
decrease in interest expense in the respective periods. There was no
cumulative adjustment under U.S. GAAP for years prior to 2000.
F-75
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
(b) In September 2001, Abraxas acquired the remaining non-controlling
interest of the Company. Consideration was comprised of 0.6 common
shares of Abraxas, in exchange for each common share of the Company.
Under U.S. GAAP, the costs assigned to assets and liabilities by the
acquiring company under a business combination are considered to
constitute a new basis of accounting. Accordingly, the historical
carrying values of assets and liabilities of the subsidiary are
comprehensively revalued based on the purchase price assigned for
consolidation purposes at the time it becomes wholly owned ("push down
accounting"). Under Canadian GAAP, comprehensive revaluation of assets
and liabilities in the financial statements of a subsidiary based on a
purchase transaction involving acquisition of all of the equity
interests is permitted, but not required. Had the consolidation
entries of Abraxas related to the acquisition been applied in the
Company's financial statements using "push down accounting", property
and equipment and future income tax liability would be reduced by
$4,074,000 and $1,736,000, respectively, accounts receivable would be
increased and interest and financing charges decreased by $984,000
(relating to certain costs of the transaction paid by the Company),
with the remaining amount of $2,338,000 recorded as a revaluation
adjustment within shareholders' equity.
(c) Under U.S. GAAP, the carrying value of petroleum and natural gas
properties and related facilities at the balance sheet date, net of
deferred income taxes and accumulated site restoration and abandonment
liability, is limited to the present value of after-tax future net
revenue from proven reserves, discounted at 10 percent, plus the lower
of cost and fair value of unproved oil and gas properties. Under
Canadian GAAP, the "ceiling test" calculation is performed using
undiscounted after-tax net revenues, less future estimated general and
administrative and financing costs plus the lower of cost and fair
value of unproved oil and gas properties. Had the ceiling test been
applied in accordance with U.S. GAAP, the write-down recorded for the
year ended December 31, 2002 would have been lower by $41,155,000
($25,464,000 after-tax). There were no differences between the
application of the Canadian and U.S. GAAP ceiling tests in 2001 and
2000, or for years prior to 2000.
F-76
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
(d) Prior to 2000, Canadian GAAP required the use of the deferral method
of accounting for income taxes. For fiscal periods beginning on or
after January 1, 2000, retroactive adoption of the liability method of
accounting for income taxes was required, which is substantially the
same as Financial Accounting Standards Board Statement No. 109 under
U.S. GAAP. However, upon adoption of the new recommendation for
Canadian GAAP, companies were permitted to record the impact of
differences in accounting and tax bases to retained earnings as a
one-time transition adjustment. Accordingly, property and equipment
would have been higher under U.S. GAAP by $682,000 for 2002 and 2001
before the impact of depletion. In addition, future income tax expense
of $480,000 would have been recorded for 1999 under U.S. GAAP.
(e) As a result of the Canadian - U.S. GAAP differences in capitalization
of interest, "push down accounting", ceiling test write-down and
adoption of the deferral method of accounting for incomes taxes as
outlined in (a), (b), (c) and (d), respectively, depletion and
depreciation expense and property and equipment under U.S. GAAP have
been adjusted for each of the years ended December 31, 2002, 2001 and
2000. The cumulative increase in depletion and depreciation expense
for years prior to 2000 was $158,000.
(f) Future income taxes have been adjusted for the year ended December 31,
2002 for the tax impact of the Canadian - U.S. GAAP differences
outlined in (a) through (e). Except for the impact on future tax
expense for 1999 as noted in (d), the cumulative impact on future
income taxes for years prior to 2002 was not significant.
(g) Prior to 2001, Canadian GAAP required the use of the imputed earnings
method for purposes of the calculation of fully diluted earnings per
share. For fiscal periods beginning on or after January 1, 2001,
retroactive application of the treasury stock method with restatement
of prior periods is required, which is substantially the same as
Financial Accounting Standards Board Statement No. 128 under U.S.
GAAP. Accordingly, no adjustments are required to conform the diluted
earnings (loss) per share figures to U.S. GAAP, except for the net
income (loss) effect of the above-noted Canadian - U.S. GAAP
differences identified.
F-77
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
The application of U.S. GAAP would have the following effect on the
Statements of Earnings (Loss):
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
$ $ $
-------- -------- --------
Net earnings (loss), as reported (47,613) 4,135 3,940
Capitalized interest (a) 168 119 69
Depreciation, depletion and site (2,401) (62) (88)
restoration (e)
Write-down of petroleum and natural gas
properties and facilities (c)
41,155 - -
Interest and financing charges (b) - 984 -
Future income tax expense (recovery) (f) (14,495) - -
-------- -------- --------
Net earnings (loss), U.S. GAAP (23,186) 5,176 3,921
======== ======== ========
Basic and diluted earnings (loss) per share,
as reported (3.71) 0.32 0.31
Effect of increase (decrease) in net
earnings (loss) under U.S. GAAP 1.90 0.09 -
-------- -------- --------
Basic and diluted earnings (loss) per share,
U.S. GAAP (g) (1.81) 0.41 0.31
======== ======== ========
</Table>
F-78
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
The application of U.S. GAAP would have the following effect on the Balance
Sheets:
<Table>
<Caption>
AS AT DECEMBER 31, 2002 AS AT DECEMBER 31, 2001
------------------------------------ --------------------------------------
CUMULATIVE CUMULATIVE
AS INCREASE U.S. AS INCREASE U.S.
REPORTED (DECREASE) GAAP REPORTED (DECREASE) GAAP
-------- ---------- ---------- ---------- ---------- ----------
ASSETS
Accounts receivable (b) 8,230 984 9,214 9,980 984 10,964
Property and equipment (a)(b)(c)(d)(e) 23,401 35,414 58,815 71,879 (3,509) 68,370
Future income taxes (f) 25,233 (12,759) 12,474 - - -
LIABILITIES
Future income taxes (d)(f) - - - 6,359 (1,736) 4,623
SHAREHOLDERS'
EQUITY (DEFICIENCY)
Revaluation adjustment (b) - (2,338) (2,338) - (2,338) (2,338)
Retained earnings (deficit)
(a)(b)(c)(d)(e)(f) (38,188) 25,977 (15,255) 9,425 1,549 10,974
</Table>
F-79
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
The application of U.S. GAAP would have the following effect on the
Statements of Cash Flows:
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
$ $ $
-------- -------- --------
OPERATING ACTIVITIES
Cash flow from operating activities, as reported 8,712 14,814 16,532
Increase (decrease) in:
Net earnings (loss) 24,427 1,041 (19)
Depletion, depreciation and site
restoration (e) 2,401 62 88
Write-down of petroleum and natural gas
properties and facilities (c) (41,155) - -
Future income tax expense (recovery) (f) 14,495 - -
Changes in non-cash working capital items (b) - (984) -
-------- -------- --------
Cash flow from operating activities, U.S. GAAP 8,880 14,933 16,601
======== ======== ========
INVESTING ACTIVITIES
Net cash (used) provided by investing activities,
as reported (42,023) (29,079) (16,262)
Increase in capital expenditures (a) (168) (119) (69)
-------- -------- --------
Net cash (used) provided by investing activities,
U.S. GAAP (42,191) (29,198) (16,331)
======== ======== ========
</Table>
The investing activities portion of the statement of cash flows for 2000
prepared under Canadian GAAP discloses the aggregate costs related to a
property swap arrangement, with adjustments to arrive at the cash component
of the transaction. Under U.S. GAAP only the net cash amount would be
presented on the statement of cash flows.
F-80
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
Under Canadian GAAP, companies are permitted to present a sub-total prior
to changes in non-cash working capital within operating activities. This
information is perceived to be useful information for various users of the
financial statements and is commonly presented by Canadian public
companies. Under U.S. GAAP, this sub-total is not permitted to be shown and
would be removed in the statements of cash flows for all periods presented.
In addition, cash flow from operations per share figures would not be
presented under U.S. GAAP.
RECENT U.S. ACCOUNTING DEVELOPMENTS
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143)
was released by the Financial Accounting Standards Board in June 2001. FAS
143 requires liability recognition for retirement obligations associated
with tangible long-lived assets. The initial amount of the asset retirement
obligation is to be recorded at fair value. The asset retirement cost equal
to the fair value of the retirement obligation is to be capitalized as part
of the cost of the related long-lived asset and amortized to expense over
the useful life of the asset. Enterprises are required to adopt FAS 143 for
fiscal years beginning after June 15, 2002. The Company is currently
assessing the impact that adoption of this standard would have on its
financial position and results of operations, in conjunction with the
January 23, 2003 transaction as described in Note 13.
The Financial Accounting Standards Board also recently issued Statement No.
144, "Accounting for the Impairment of Disposal of Long-Lived Assets" (FAS
144). FAS 144 will replace previous United States generally accepted
accounting principles regarding accounting for impairment of long-lived
assets and accounting and reporting for discontinued operations. FAS 144
retains the fundamental provisions of the prior standard for recognizing
and measuring impairment losses on long-lived assets. FAS 144 retains the
basic provisions of the prior standard for presentation of discontinued
operations in the income statement, but broadens that presentation to
include a component of an entity rather than a segment of a business.
Enterprises are required to adopt FAS 144 for fiscal years beginning after
December 15, 2001. The Company has adopted the accounting standard
effective January 1, 2002. The standard is not expected to have a
significant future impact on the Company's financial position and results
of operations.
F-81
<Page>
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED)
The Financial Accounting Standards Board also recently issued Statement No.
146, "Accounting for Costs Associated With Exit or Disposal Activities"
(FAS 146). FAS 146 addresses financial accounting and reporting for costs
associated with exit or disposal activities and nullifies Emerging Issues
Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." The provisions of
this Statement are effective for exit or disposal activities that are
initiated after December 31, 2002, with early application encouraged. The
standard is not expected to have a significant impact on the Company's
financial position or results of operations.
13. SUBSEQUENT EVENTS
On January 23, 2003, Abraxas completed the sale of all of the outstanding
common shares of the Company to an unrelated third party (the "Purchaser")
for gross cash proceeds of approximately $110,790,000, subject to closing
adjustments. Upon closing of the sale, the Company was required to repay
the outstanding indebtedness including accrued interest under the Mirant
Facility, totaling $72,847,000. Prior to the sale, certain petroleum and
natural gas assets of the Company with a net book value of $8,871,000 were
transferred to a related newly-formed subsidiary of Abraxas, a portion of
which will be developed jointly under farmout arrangements with the
Purchaser.
F-82
<Page>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following table sets forth the expenses (other than underwriting
discounts and commissions) in connection with the offering described in this
Registration Statement, all of which shall be paid by us. All of such amounts
(except the SEC Registration Fee) are estimated.
<Table>
SEC Registration Fee..................................................$ 5,995
-----------
Federal Taxes.........................................................$ --
-----------
State and Local Taxes.................................................$ --
-----------
Trustee and Transfer Agent Fees.......................................$ 10,000
-----------
Printing and Mailing Costs............................................$ 26,000
-----------
Legal Fees and Expenses...............................................$ 335,000
-----------
Accounting Fees and Expenses..........................................$ 125,000
-----------
Miscellaneous.........................................................$ 15,000
-----------
</Table>
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Abraxas' Articles of Incorporation contain a provision that eliminates
the personal monetary liability of directors and officers to Abraxas and its
stockholders for a breach of fiduciary duties to the extent currently allowed
under the Nevada General Corporation Law (the "Nevada Statute"). If a director
or officer of Abraxas were to breach his fiduciary duties, neither Abraxas nor
its stockholders could recover monetary damages, and the only course of action
available to Abraxas' stockholders would be equitable remedies, such as an
action to enjoin or rescind a transaction involving a breach of fiduciary duty.
To the extent certain claims against directors or officers are limited to
equitable remedies, this provision of Abraxas' Articles of Incorporation may
reduce the likelihood of derivative litigation and may discourage stockholders
or management from initiating litigation against directors or officers for
breach of their duty of care. Additionally, equitable remedies may not be
effective in many situations. If a stockholder's only remedy is to enjoin the
completion of the Board of Director's action, this remedy would be ineffective
if the stockholder did not become aware of a transaction or event until after it
had been completed. In such a situation, it is possible that the stockholders
and Abraxas would have no effective remedy against the directors or officers.
Liability for monetary damages has not been eliminated for acts or
omissions which involve intentional misconduct, fraud or a knowing violation of
law or payment of an improper dividend in violation of section 78.300 of the
Nevada Statute. The limitation of liability also does not eliminate or limit
director liability arising in connection with causes of action brought under the
Federal securities laws.
The Nevada Statute permits a corporation to indemnify certain persons,
including officers and directors, who are (or are threatened to be made) parties
against all expenses (including attorneys' fees) actually and reasonably
incurred by, or imposed upon, him in connection with the defense by reason of
his being or having been a director or officer if he acted in good faith and in
a manner which he reasonably believed to be in or not opposed to the best
interests of the corporation and, with respect to any criminal action or
proceeding, had no reasonable cause to believe his conduct was unlawful, except
where he has been adjudged by a court of competent jurisdiction (and after
exhaustion of all appeals) to be liable for gross negligence or willful
misconduct in the performance of his duty. The Bylaws of Abraxas provide
indemnification to the same extent allowed pursuant to the foregoing provisions
of the Nevada Statute.
Nevada corporations also are authorized to obtain insurance to protect
officers and directors from certain liabilities, including liabilities against
which the corporation cannot indemnify its directors and officers. Alberta
Business Corporation Act corporations are permitted to obtain such insurance
also, except for liability relating to the failure to act honestly and in good
faith with a view to the best interests of the corporation. Abraxas currently
has a directors' and officers' liability insurance policy in effect providing
$3.0 million in coverage and an additional $1.0 million in coverage for certain
employment related claims.
II-1
<Page>
Abraxas has entered into indemnity agreements with each of its
directors and officers. These agreements provide for indemnification to the
extent permitted by the Nevada Statute.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES
Since January 2000, we have issued and sold the following unregistered
securities:
(a) On August 1, 2000, Abraxas issued a warrant to purchase 750,000 shares
at an exercise price of $3.50 per share. The warrant was issued pursuant to
Section 4(2) of the Securities Act of 1933, as amended.
(b) On January 23, 2003, Abraxas issued $109,523,000 principal amount of
11 1/2% Secured Notes due 2007, Series A and 5,633,291 shares of Abraxas common
stock. These securities were issued pursuant to Section 4(2) of the Securities
Act of 1933, as amended.
(c) On July 29, 2003, Abraxas issued 106,977 shares of Abraxas common
stock in connection with the acquisition of Wind River. These securities were
issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to
Abraxas' Registration Statement on Form S-4, No. 33-36565).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas
dated October 22, 1990 (Filed as Exhibit 3.3 to Abraxas' Registration
Statement on Form S-4, No. 33-36565).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas
dated December 18, 1990 (Filed as Exhibit 3.4 to Abraxas' Registration
Statement on Form S-4, No. 33-36565).
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas
dated June 8, 1995 (Filed as Exhibit 3.4 to the Abraxas' Registration
Statement on Form S-3, No. 333-00398 (the "1995 S-3 Registration
Statement")).
3.5 Articles of Amendment to the Articles of Incorporation of Abraxas
dated as of August 12, 2000 (Filed as Exhibit 3.5 to Abraxas' Annual
Report on Form 10-K filed April 2, 2001).
3.6 Articles of Incorporation of Sandia Oil & Gas (Filed as Exhibit 3.7 to
Abraxas and Canadian Abraxas' Registration Statement on Form S-4, No.
333-79349 (the "1999 Exchange Offer Registration Statement")).
*3.7 Articles of Incorporation of Sandia Operating Corp.
3.8 Articles of Incorporation of Wamsutter Holdings, Inc. (Filed as
Exhibit 3.7 to the Abraxas, Sandia Oil & Gas Corporation and New Cache
Petroleums Ltd. Registration Statement on Form S-1, No. 333-95281 (the
"2000 S-1 Registration Statement")).
*3.9 Articles of Incorporation of Western Associated Energy Corporation.
*3.10 Articles of Incorporation of Eastside Coal Company, Inc.
*3.11 Certificate of Incorporation of Grey Wolf Exploration Inc.
3.12 Amended and Restated Bylaws of Abraxas (Filed as Exhibit 3.6 to
Abraxas' Annual Report on Form 10-K filed April 5, 2002).
*3.13 Amended and Restated By-Laws of Sandia Oil & Gas Corporation.
*3.14 By-Laws of Sandia Operating Corp.
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3.15 By-Laws of Wamsutter Holdings, Inc. (Filed as Exhibit 3.11 to the 2000
S-1 Registration Statement).
*3.16 By-Laws of Western Associated Energy Corporation.
*3.17 By-Laws of Eastside Coal Company, Inc.
*3.18 By-Laws of Grey Wolf Exploration Inc.
4.1 Specimen Common Stock Certificate of Abraxas (Filed as Exhibit 4.1 to
Abraxas' Registration Statement on Form S-4, No. 33-36565).
4.2 Specimen Preferred Stock Certificate of Abraxas (Filed as Exhibit 4.2
to Abraxas' Annual Report on Form 10-K filed on March 31, 1995).
4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and
First Union National Bank of North Carolina ("FUNB") (Filed as Exhibit
4.1 to Abraxas' Registration Statement on Form 8-A filed on December
6, 1994).
4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between
Abraxas and American Stock Transfer and Trust Company (Filed as
Exhibit 1 to Amendment No. 1 to Abraxas' Registration Statement on
Form 8-A filed on August 20, 1997).
4.5 Second Amendment to Rights Agreement as of May 22, 1998, by and
between Abraxas and American Stock Transfer & Trust Company (Filed as
Exhibit 1 to Amendment No. 2 to Abraxas' Registration Statement on
Form 8-A filed on August 24, 1998).
4.6 Indenture dated as of January 23, 2003, among Abraxas, as Issuer, the
Subsidiary Guarantors party thereto, and U.S. Bank, N.A., as Trustee,
relating to Abraxas' 11-1/2% Secured Notes due 2007 (the "Indenture")
(Filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K filed
February 6, 2003).
4.7 Registration Rights Agreement dated as of January 23, 2003 by and
among Abraxas, Sandia Oil & Gas Corporation, Sandia Operating Corp.,
Wamsutter Holdings, Inc., Grey Wolf Exploration Inc. and Jefferies &
Company, Inc. (Filed as Exhibit 10.4 to Abraxas' Current Report on
Form 8-K filed February 6, 2003).
4.8 Form of 11 1/2% Secured Note due 2007 (Filed as Exhibit A to the
Indenture).
*5.1 Opinion of Cox & Smith Incorporated.
*5.2 Opinion of Osler, Hoskin & Harcourt LLP.
+10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as
amended and restated (Filed as Exhibit 10.7 to Abraxas' Annual Report
on Form 10-K filed April 14, 1993).
+10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as
amended and restated (Filed as Exhibit 10.8 to Abraxas' Annual Report
on Form 10-K filed April 14, 1993).
+10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan
(Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed
April 14, 1993).
+10.4 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan (Filed as
Exhibit 10.4 to Abraxas' Registration Statement on Form S-4, No.
333-18673 (the "1996 Exchange Offer Registration Statement)).
+10.5 Abraxas Petroleum Corporation Director Stock Option Plan (Filed as
Exhibit 10.5 to 1996 Exchange Offer Registration Statement).
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+10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors
(Filed as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed
on April 12, 1994).
+10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan (Filed as
Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April
12, 1994).
+10.8 Abraxas Petroleum Corporation Incentive Performance Bonus Plan (Filed
as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April
12, 1994).
10.9 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas
and Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to
Abraxas' and Canadian Abraxas' Registration Statement on Form S-1,
Registration No. 33-66446).
10.10 Form of Indemnity Agreement between Abraxas and each of its directors
and officers (Filed as Exhibit 10.30 to Abraxas' and Canadian Abraxas'
Registration Statement on Form S-1, Registration No. 33-66446).
+10.11 Employment Agreement between Abraxas and Robert L. G. Watson (Filed as
Exhibit 10.19 to the 2000 S-1 Registration Statement).
+10.12 Employment Agreement between Abraxas and Chris E. Williford (Filed as
Exhibit 10.20 to the 2000 S-1 Registration Statement).
+10.13 Employment Agreement between Abraxas and Stephen T. Wendel (Filed as
Exhibit 10.26 to the 1995 S-3 Registration Statement).
+10.14 Employment Agreement between Abraxas and Robert W. Carington, Jr
(Filed as Exhibit 10.22 to the 2000 S-1 Registration Statement).
10.15 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
Basil Street Company (Filed as Exhibit 10.15 to Abraxas Annual Report
on Form 10-K filed on April 2, 2001).
10.16 Common Stock Purchase Warrant dated September 1, 2000 between Jessup &
Lamont Holdings (Filed as Exhibit 10.16 to Abraxas Annual Report on
Form 10-K filed on April 2, 2001).
10.17 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
TNC, Inc. (Filed as Exhibit 10.17 to Abraxas Annual Report on Form
10-K filed on April 2, 2001).
10.18 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
Charles K. Butler (Filed as Exhibit 10.17 to Abraxas Annual Report on
Form 10-K filed on April 2, 2001).
10.19 Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of
November 12, 1998 by and between Wamsutter Holdings, Inc. and TIFD
III-X Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form
8-K filed November 30, 1998).
10.20 Purchase Agreement for Dollar Denominated Production Payment dated as
of October 6, 1999 by and between Abraxas and Southern Producer
Services, L.P. (Filed as Exhibit 10.1 to Abraxas' Quarterly Report on
Form 10-Q filed November 15, 1999).
10.21 Conveyance of Dollar Denominated Production Payment dated as of
October 6, 1999 by and between Abraxas and Southern Producer Services,
L.P. (Filed as Exhibit 10.2 to Abraxas' Quarterly Report on Form 10-Q
filed November 15, 1999).
10.22 Purchase and Sale Agreement dated November 21, 2002, by and among
Abraxas, as Seller, Primewest Gas Inc., as Purchaser, Primewest Energy
Inc., as Guarantor, Canadian Abraxas and Grey Wolf Exploration
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Inc., as the Companies (Filed as Exhibit 10.1 to Abraxas' Current
Report on Form 8-K/A filed December 9, 2002).
10.23 Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest
Energy, Inc. (Previously filed as Exhibit 10.2 to Abraxas' Current
Report on Form 8-K/A filed on December 9, 2002).
10.24 Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest
Energy, Inc. (Previously filed as Exhibit 10.3 to Abraxas' Current
Report on Form 8-K/A filed on December 9, 2002).
10.25 Loan And Security Agreement dated as of January 22, 2003, by and among
Abraxas, as Borrower, the Subsidiaries of Abraxas that are Signatories
thereto, as Guarantors, the Lenders that are Signatories thereto, as
Lenders, and Foothill Capital Corporation, as the Arranger and
Administrative Agent (Filed as Exhibit 10.5 to Abraxas' Current Report
on Form 8-K filed February 6, 2003).
10.26 Intercreditor and Subordination Agreement dated as of January 23,
2003, by and among Foothill, in its capacity as agent (in such
capacity, together with any successor in such capacity, the "Senior
Agent") for the lenders who are from time to time parties to the Loan
Agreement (the "Senior Lenders"), U.S. Bank, N.A., a national banking
association in its capacity as trustee (in such capacity, together
with any successor in such capacity, the "Trustee") for the holders of
the 11 1/2% Secured Notes Due 2007, issued under the Indenture. (Filed
as Exhibit 10.6 to Abraxas' Current Report on Form 8-K filed February
6, 2003).
16.1 Letter addressing change in certifying accountant (Filed on Abraxas'
Form 8-K filed on August 22, 2001).
*21.1 Subsidiaries of Abraxas.
**23.1 Consent of Deloitte & Touche LLP
**23.2 Consent of Deloitte & Touche LLP Chartered Accountants
*23.3 Consent of DeGolyer and MacNaughton.
*23.4 Consent of McDaniel & Associates Consultants, Ltd.
*23.5 Consent of Cox & Smith Incorporated (Included in Exhibit 5.1).
*23.6 Consent of Osler, Hoskin & Harcourt LLP.
*24.1 Power of Attorney of Craig S. Bartlett, Jr.
*24.2 Power of Attorney of Franklin Burke.
*24.3 Power of Attorney of Frederick M. Pevow, Jr.
*24.4 Power of Attorney of James C. Phelps.
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*24.5 Power of Attorney of Joseph A. Wagda.
*25.1 Statement of eligibility of trustee for the Indenture.
27.1 Financial Data Schedule (Omitted pursuant to Regulation S-K, Item
601(c)).
* Previously filed.
** Filed herewith.
+ Management Compensatory Plan or Agreement.
ITEM 17. UNDERTAKINGS
A. The undersigned registrants hereby undertake:
(1) To file, during any period in which offers or sales are
being made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by
section 10(a)(3) of the Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events
arising after the effective date of the registration statement (or the most
recent post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth in the
registration statement. Notwithstanding the foregoing, any increase or decrease
in volume of securities offered (if the total dollar value of securities offered
would not exceed that which was registered) and any deviation from the low or
high end of the estimated maximum offering range may be reflected in the form of
prospectus filed with the Commission pursuant to Rule 424(b) if, in the
aggregate, the changes in volume and price represent no more than a 20% change
in the maximum aggregate offering price set forth in the "Calculation of
Registration Fee" table in the effective registration statement.
(iii) To include any material information with respect
to the plan of distribution not previously disclosed in the registration
statement or any material change to such information in the registration
statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed to be
a new registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(3) To remove from registration by means of a post-effective
amendment any of the securities being registered which remain unsold at the
termination of the offering.
B. Each of the undersigned registrants hereby undertakes that,
for purposes of determining any liability under the Securities Act of 1933, each
filing of the registrant's annual report pursuant to Section 13(a) or Section
15(d) of the Securities Exchange Act of 1934 that is incorporated by reference
in the registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
C. Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of each of the registrants pursuant to the foregoing provisions, or
otherwise, the registrants have been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Act and is, therefore, unenforceable. In the event that a
claim for indemnification against such liabilities (other than the payment by
the registrants of expenses incurred or paid by a director, officer or
controlling person in the successful defense of any action, suit or proceedings)
is asserted by such director, officer or controlling person in connection with
the securities being registered, the registrants
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will, unless in the opinion of their counsel the matter has been settled by
controlling precedent, submit to a court of appropriate jurisdiction the
question whether such indemnification by either of them is against public policy
as expressed in the Act and will be governed by the final adjudication of such
issue.
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
ABRAXAS PETROLEUM CORPORATION
By: /s/ Robert L. G. Watson
------------------------
Chairman of the Board, Chief Executive
Officer and President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson Chairman of the Board, August 11, 2003
- ---------------------- President, Chief Executive Officer
Robert L.G. Watson (Principal Executive Officer) and Director
of Abraxas
/s/ Chris E. Williford Executive Vice President, August 11, 2003
- ------------------------------- Treasurer, and Chief Financial
Chris E. Williford Officer (Principal
Financial and Accounting Officer)
of Abraxas
/s/ Robert W. Carington Executive Vice President August 11, 2003
- ------------------------------- of Abraxas
Robert W. Carington, Jr.
* Director of Abraxas August 11, 2003
- -------------------------------
Craig S. Bartlett, Jr.
* Director of Abraxas August 11, 2003
- -------------------------------
Franklin A. Burke
Director of Abraxas
- -------------------------------
Ralph F. Cox
Director of Abraxas
- -------------------------------
Dennis E. Logue
* Director of Abraxas August 11, 2003
- -------------------------------
James C. Phelps
* Director of Abraxas August 11, 2003
- -------------------------------
Joseph A. Wagda
*By: /s/ Chris E. Williford
- ---------------------------
Chris E. Williford
Attorney-in-fact
</Table>
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
SANDIA OIL & GAS CORPORATION
By: /s/ Robert L.G. Watson
-----------------------
President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson President (Principal Executive
- ------------------------------- Officer) and Director of August 11, 2003
Robert L.G. Watson Sandia Oil & Gas Corporation
/s/ Chris E. Williford Vice President (Principal August 11, 2003
- ------------------------------- Financial and Accounting
Chris E. Williford Officer) and Director of Sandia
Oil & Gas Corporation
/s/ Robert W. Carington Vice President and Director August 11, 2003
- ------------------------------- of Sandia Oil & Gas Corporation
Robert W. Carington, Jr.
</Table>
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
SANDIA OPERATING CORP.
By: /s/ Robert L.G. Watson
-----------------------
President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson President (Principal Executive
- ------------------------------- Officer) and Director of August 11, 2003
Robert L.G. Watson Sandia Operating Corp.
/s/ Chris E. Williford Vice President (Principal August 11, 2003
- ------------------------------- Financial and Accounting
Chris E. Williford Officer) and Director of Sandia
Operating Corp.
/s/ Robert W. Carington Vice President and Director August 11, 2003
- ------------------------------- of Sandia Operating Corp.
Robert W. Carington, Jr.
</Table>
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
WAMSUTTER HOLDINGS, INC.
By: /s/ Robert L.G. Watson
-----------------------
President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson President (Principal Executive
- ------------------------------- Officer) and Director of August 11, 2003
Robert L.G. Watson Wamsutter
/s/ Chris E. Williford Vice President (Principal August 11, 2003
- ------------------------------- Financial and Accounting
Chris E. Williford Officer) and Director of Wamsutter
/s/ Robert W. Carington Vice President and Director August 11, 2003
- ------------------------------- of Wamsutter
Robert W. Carington, Jr.
</Table>
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
WESTERN ASSOCIATED ENERGY CORPORATION
By: /s/ Robert L.G. Watson
-----------------------
President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson President (Principal Executive August 11, 2003
- ------------------------------- Officer) and Director of
Robert L.G. Watson Western Associated Energy
Corporation
/s/ Chris E. Williford Vice President (Principal August 11, 2003
- ------------------------------- Accounting Officer) and
Chris E. Williford Director of Western Associated
Energy Corporation
/s/ Robert W. Carington Vice President and August 11, 2003
- ------------------------------- Director of Western
Robert W. Carington, Jr. Associated Energy Corporation
</Table>
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
EASTSIDE COAL COMPANY, INC.
By: /s/ Robert L.G. Watson
-----------------------
President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson President (Principal Executive August 11, 2003
- ------------------------------- Officer) and Director of
Robert L.G. Watson Eastside Coal Company, Inc.
/s/ Chris E. Williford Vice President (Principal August 11, 2003
- ------------------------------- Accounting Officer) and
Chris E. Williford Director of Eastside Coal
Company, Inc.
/s/ Robert W. Carington Vice President and August 11, 2003
- ------------------------------- Director of Eastside Coal
Robert W. Carington, Jr. Company, Inc.
</Table>
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SIGNATURES
Pursuant to the requirements of the Securities Act, the undersigned
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of San
Antonio, Texas, on August 11, 2003.
GREY WOLF EXPLORATION INC.
By: /s/ Robert L.G. Watson
-----------------------
President
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Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the date indicated.
<Table>
<Caption>
Signature Name and Title Date
- --------- -------------- ----
/s/ Robert L.G. Watson President (Principal Executive
- ------------------------------- Officer) and Director of August 11, 2003
Robert L.G. Watson Grey Wolf Exploration Inc.
/s/ Chris E. Williford Vice President (Principal August 11, 2003
- ------------------------------- Financial and Accounting
Chris E. Williford Officer) of Grey
Wolf Exploration Inc.
/s/ Vince Tkachick Vice President/COO and Director August 11, 2003
Vince Tkachick of Grey Wolf Exploration Inc.
</Table>
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EXHIBIT INDEX
EXHIBIT NUMBER:
23.1 Consent of Deloitte & Touche LLP
23.2 Consent of Deloitte & Touche LLP Chartered Accountants