<Page>
As filed with the Securities and Exchange Commission on April 17, 2003
Registration No. 333-103028
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 1
TO
FORM S-4
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
John T. Bibb
(210) 554-5500
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<Page>
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO
THE PUBLIC: As soon as practicable after this Registration Statement becomes
effective.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) 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 this Form is a post-effective amendment filed pursuant to Rule
462(d) 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. [ ] ______________________
CALCULATION OF REGISTRATION FEE
<Table>
<Caption>
PROPOSED
MAXIMUM PROPOSED MAXIMUM AMOUNT OF
TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE AGGREGATE REGISTRATION
SECURITIES TO BE REGISTERED REGISTERED PER UNIT OFFERING PRICE FEE (4)
--------------------------- ---------- -------- -------------- -------
11 1/2% Secured Notes Due 2007, Series B $113,439,051(5) (6) $37,298,457(1)(6) $3,412.55
Guarantees (2) -- -- None (3)
</Table>
(1) Estimated solely for the purpose of calculating the registration fee in
accordance with Rule 457(f)(1).
(2) The 11 1/2% Secured Notes due 2007, Series B, of Abraxas Petroleum
Corporation being registered will be guaranteed by each of the
Subsidiary Guarantors.
(3) Pursuant to Rule 457(n).
(4) A fee of $3,274.74 was previously paid by Registrant in connection with
the filing on February 7, 2003.
(5) Represents $109,523,000 in principal amount of notes registered in
connection with the filing on February 7, 2003, plus an additional
$3,916,051 in principal amount of notes.
(6) The proposed maximum offering price for the $109,523,000 in principal
amount of notes originally registered on February 7, 2003 remains
unchanged pursuant to Rule 457(a) as calculated in accordance with Rule
457(f)(1) at 32.5% of face value. The proposed maximum offering price
for the additional $3,916,051 in principal amount of notes registered
pursuant hereto is 43.5% of face value, calculated in accordance with
Rule 457(f)(1), resulting in an incremental amount to the maximum
aggregate offering price of $1,703,482 and an additional registration
fee of $137.81.
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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SUBJECT TO COMPLETION, DATED APRIL 17, 2003
ABRAXAS PETROLEUM CORPORATION
OFFER TO EXCHANGE UP TO
$113,439,051 PRINCIPAL AMOUNT 11 1/2% SECURED NOTES DUE 2007, SERIES B
FOR ANY AND ALL OUTSTANDING
$113,439,051 PRINCIPAL AMOUNT 11 1/2% SECURED NOTES DUE 2007, SERIES A
THE SERIES A/B EXCHANGE OFFER WILL EXPIRE AT MIDNIGHT, NEW YORK CITY TIME,
ON ____________ ___, 2003, UNLESS EXTENDED.
THE 11 1/2% SECURED NOTES DUE 2007, SERIES A
o were originally offered and sold on January 23, 2003 in an
aggregate principal amount of $109,706,000;
o will mature on May 1, 2007;
o accrue interest from the date of issuance at a fixed annual
rate of 11 1/2%, payable in cash semi-annually beginning 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 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,
and as a result, we anticipate issuing additional notes on May
1, 2003 in an aggregate principal amount of $3,733,051;
o will, upon an event of default, accrue interest at an annual
rate of 16.5%;
o are guaranteed by all of Abraxas' current subsidiaries, Sandia
Oil & Gas Corporation, Sandia Operating Corp., Wamsutter
Holdings, Inc., Western Associated Energy Corporation and
Eastside Coal Company, Inc., and our newly-formed wholly-owned
Canadian subsidiary, Grey Wolf Exploration, Inc., and will be
guaranteed by all of Abraxas' future subsidiaries;
o 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
o are not listed on any national securities exchange.
THE 11 1/2% SECURED NOTES DUE 2007, SERIES B
o are offered in exchange for an equal principal amount of our
outstanding Series A notes, described above;
o evidence the same indebtedness as our outstanding Series A
notes and are entitled to the benefits of the indenture under
which those notes were issued;
o are substantially identical in all material respects to our
outstanding Series A notes, except for certain transfer
restrictions and registration rights; and
o are not listed on any national securities exchange.
THE SERIES A/B EXCHANGE OFFER
o expires at Midnight, New York City time, on ____________ ___,
2003, unless extended;
o is our offer to exchange our Series B notes for an equal
amount of our outstanding Series A notes;
o is not a taxable exchange for U.S. Federal income tax
purposes; and
o is not subject to any condition other than that the Series A/B
Exchange Offer not violate applicable law or any applicable
interpretation of the staff of the SEC.
----------------------
YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 17 OF
THIS PROSPECTUS BEFORE PARTICIPATING IN THE SERIES A/B EXCHANGE OFFER.
----------------------
NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR
DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR
COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
April__, 2003
<Page>
NOTICE TO NEW HAMPSHIRE RESIDENTS
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED UNDER THIS CHAPTER WITH THE STATE OF NEW HAMPSHIRE NOR
THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN
THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT
ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER
ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A
SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY
WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO,
ANY PERSON, SECURITY, OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE
MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION
INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.
2
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TABLE OF CONTENTS
<Table>
Cautionary Statements Regarding Forward-Looking Information............................................ 4
Summary................................................................................................ 5
Risk Factors............................................................................................17
Use of Proceeds.........................................................................................27
Ratio of Earnings to Fixed Charges......................................................................27
Capitalization..........................................................................................27
Plan of Distribution....................................................................................28
The Series A/B Exchange Offer...........................................................................28
Unaudited Pro Forma Condensed Consolidated Financial Statements.........................................36
Selected Historical Financial Data......................................................................40
Management's Discussion and Analysis of Financial Condition and Results of Operations...................41
Business ..............................................................................................58
Management..............................................................................................75
Executive Compensation..................................................................................77
Certain Transactions....................................................................................80
Principal Stockholders..................................................................................81
Description of the Exchange Notes.......................................................................82
Certain U.S. Federal Income Tax Considerations.........................................................129
Book-Entry; Delivery and Form..........................................................................135
Where You Can Find More Information....................................................................137
Legal Matters..........................................................................................137
Experts .............................................................................................137
Glossary of Terms......................................................................................138
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.
----------------------
Until ____________________, 2003, all dealers that effect transactions
in these securities, whether or not participating in this offering, may be
required to deliver a prospectus. This is in addition to the dealers' obligation
to deliver a prospectus when acting as underwriters and with respect to their
unsold allotments or subscriptions.
3
<Page>
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:
o our high debt level;
o our ability to raise capital;
o our limited liquidity;
o economic and business conditions;
o price and availability of alternative fuels;
o political and economic conditions in oil producing
countries, especially those in the Middle East;
o our success in development, exploitation and
exploration activities;
o planned capital expenditures;
o prices for crude oil and natural gas;
o declines in our production of crude oil and natural
gas;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this prospectus.
4
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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
exploration, exploitation, development and production of crude oil and natural
gas. Since January 1, 1991, our principal means of growth has been through the
acquisition and subsequent development and exploitation of producing properties
and related assets. As a result of our historical acquisition activities, we
believe we have a substantial inventory of low risk opportunities, the
exploitation and development of which are critical to the maintenance and growth
of our current production levels. We seek to complement our exploitation 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. As a result of the sale of the capital
stock of Canadian Abraxas and Old Grey Wolf, the results of operations of
Canadian Abraxas and Old Grey Wolf are reflected in our Financial Statements and
in this prospectus as "discontinued operations" and our remaining operations are
referred to in our Financial Statements and in this prospectus as "continuing
operations" or "continued operations." Unless otherwise noted, all disclosures
are for continuing operations.
Our principal areas of operation are Texas, western Canada and Wyoming.
At December 31, 2002, we owned interests in 459,880 gross acres (370,589 net
acres) applicable to our continuing operations and operated properties
accounting for 87% 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 of our continuing operations were 112.5
Bcfe with an aggregate PV-10 of $136.6 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 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 million, due to the accounting
treatment under generally accepted accounting principles 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 58.
5
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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
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007, Series A, with a
principal amount equal to $610; and
o 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, 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.
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:
o to pay fees and expenses of the sale of Canadian
Abraxas and Old Grey Wolf of approximately $2.5
million;
6
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o to redeem our outstanding 12?% 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
o 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?% 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.
THE SERIES A/B EXCHANGE OFFER
On January 23, 2003, Abraxas issued $109,706,000 of its 11 1/2% Senior
Secured Notes due 2003, Series A, in a private exchange offer, and Abraxas
anticipates issuing an additional $3,733,051 in principal amount of Series A
notes on May 1, 2003 as payment of interest in kind. The Series A notes, or
outstanding notes, are, and the Series B notes, or exchange notes (outstanding
notes and exchange notes are sometimes referred to as "notes"), will be,
guaranteed by all of our wholly-owned subsidiaries, Sandia Oil & Gas Corp.,
Sandia Operating Corp. (a wholly-owned subsidiary of Sandia Oil & Gas Corp.),
Wamsutter Holdings, Inc., Western Associated Energy Corporation, Eastside Coal
Company, Inc., and New Grey Wolf and all of our future subsidiaries. If Abraxas
cannot make payment on the notes when they are due, the guarantors must make
them instead.
Simultaneously with the exchange offer, the guarantor subsidiaries
and Abraxas agreed to provide the holders of the outstanding notes with
certain registration rights pursuant to a registration rights agreement.
Under the registration rights agreement, Abraxas must deliver this prospectus
to the holders of the outstanding notes and must complete the Series A/B
Exchange Offer within 30 business days after the exchange offer registration
statement has been declared effective, subject to any extension that may be
legally required. If there is a registration default related to the Series
A/B Exchange Offer, we must pay liquidated damages to the holders of the
outstanding
7
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notes until such registration default is cured. You may exchange your
outstanding notes for exchange notes with substantially the same terms in the
Series A/B Exchange Offer. You should read the discussion under the heading
"Summary of Terms of the Exchange Notes" and "Description of the Exchange
Notes" for further information regarding the exchange notes.
We believe that holders of the outstanding notes, upon completion of
the Series A/B Exchange Offer, may resell the exchange notes without complying
with the registration and prospectus delivery provisions of the Securities Act,
if certain conditions are met. You should read the discussion under the headings
"Summary of the Series A/B Exchange Offer", "Plan of Distribution" and "The
Series A/B Exchange Offer - Resales of Exchange Notes" for further information
regarding the Series A/B Exchange Offer and resales of the exchange notes.
The exchange notes will be recorded at the same carrying value as
the outstanding notes. Accordingly, no gain or loss for accounting purposes
will be recognized upon the closing of the Series A/B Exchange Offer. Costs
associated with the Series A/B Exchange Offer will be expensed as incurred.
SUMMARY OF THE SERIES A/B EXCHANGE OFFER
<Table>
Registration Rights............................... We issued the outstanding notes on January 23, 2003 to
persons participating in the private exchange offer, and we
anticipate issuing additional notes on May 1, 2003 as
payment in kind of interest accrued on the outstanding
notes. Simultaneously with the initial issuance of the
outstanding notes, we agreed to provide the holders of the
outstanding notes with certain registration rights. The
registration rights agreement provides for the Series A/B
Exchange Offer.
You may exchange your outstanding notes for exchange notes,
which have substantially identical terms. After the Series
A/B Exchange Offer is completed, you will not be entitled to
any further rights to exchange your outstanding notes for
exchange notes; however, you may be entitled to certain
registration rights related to a shelf registration statement,
in accordance with the terms of the registration rights
agreement.
The Series A/B Exchange Offer .................... We are offering to exchange $113,439,051 total principal
amount of our 11 1/2% Secured Notes due 2007, Series B, the
offering of which has been registered under the Securities
Act, for all outstanding 11 1/2% Secured Notes due 2007,
Series A, whether issued in the January 2003 private
exchange offer or on May 1, 2003 as payment in kind of
accrued interest on the outstanding notes. To exchange
your outstanding notes, you must have properly tendered
them, and we must have accepted them. We will exchange all
outstanding notes that you validly tender and do not
validly withdraw. We will issue registered exchange notes
at or promptly after the end of the Series A/B Exchange
Offer.
Resales........................................... We believe that you can offer for resale, resell or
otherwise transfer the exchange notes without complying
with the registration and prospectus delivery requirements
of the Securities Act if:
o you are acquiring the exchange notes in the ordinary
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course of your business;
o you are not participating, do not intend to
participate, and have no arrangement or understanding
with any person to participate in, the distribution of
the exchange notes; and
o you are not an "affiliate" of Abraxas, as defined in
Rule 405 of the Securities Act.
If any of these conditions is not satisfied and you transfer
any exchange notes without delivering a proper prospectus or
without qualifying for a registration exemption, you may incur
liability under the Securities Act. We will not assume
or indemnify you against such liability.
Each broker-dealer that receives exchange notes for its own
account in exchange for outstanding notes that such
broker-dealer acquired through market-making or other trading
activities must acknowledge that it will deliver a proper
prospectus when it transfers any exchange notes. A
broker-dealer may use this prospectus for a limited period for
an offer to resell, a resale or other transfer of the exchange
notes.
Expiration Time................................... The Series A/B Exchange Offer expires at Midnight, New York
City time, on ____________, 2003, unless we extend the
expiration time.
Conditions to the Series A/B Exchange Offer....... The Series A/B Exchange Offer is subject to customary
conditions, some of which we may waive. You should read
the discussion under the heading "The Series A/B Exchange
Offer--Conditions to the Series A/B Exchange Offer" on page
34 of this prospectus for more information.
Accrued Interest on the Exchange Notes............ The exchange notes will bear interest from May 1, 2003.
Procedures for Tendering Outstanding Notes........ Abraxas issued the outstanding notes in both global and
certificated form. When the outstanding notes were issued in
January 2003, Abraxas deposited a global note with U.S. Bank,
N.A., as custodian for Cede & Co., the nominee for The
Depository Trust Company, or DTC, the book-entry depositary.
Additionally, at the same time, Abraxas issued notes directly
to noteholders in certificated form. Abraxas expects to make a
payment of interest in kind on the outstanding notes on May 1,
2003 by issuing additional notes in both global and
certificated form. Beneficial interests in the outstanding
notes, which are held by direct or indirect participants in
DTC, are shown on records maintained in book-entry form by
DTC.
You may tender your outstanding notes held in book-entry form
through book-entry transfer in accordance with DTC's Automated
Tender Offer Program, or ATOP. If you hold certificated
outstanding notes, or to otherwise tender your
9
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outstanding notes by a means other than book-entry transfer, a letter of
transmittal must be completed and signed according to the
instructions contained in the letter. The letter of
transmittal and any other documents required by the letter of
transmittal must be delivered to the exchange agent by mail,
facsimile, hand delivery or overnight courier. In addition,
you must deliver the outstanding notes to the exchange agent
or comply with the procedures for guaranteed delivery. You
should read the discussions under the heading "The Series A/B
Exchange Offer--Procedures for Tendering Outstanding Notes" on
page 31 of this prospectus for more information.
Do not send letters of transmittal and certificates
representing outstanding notes to Abraxas. Send these
documents only to the exchange agent. You should read the
discussion under the heading "The Series A/B Exchange
Offer--Exchange Agent" on page 35 of this prospectus for more
information.
Special Procedures for Beneficial Owners.......... If you are a beneficial owner whose outstanding notes are
registered in the name of a broker, dealer, commercial
bank, trust company or other nominee and wish to tender
your outstanding notes in the Series A/B Exchange Offer,
please contact the registered holder as soon as possible
and instruct it to tender on your behalf and comply with
our instructions set forth elsewhere in this prospectus.
Withdrawal Rights................................. You may withdraw the tender of your outstanding notes at
any time before Midnight, New York City time, on the
expiration date by following the procedures for withdrawal
set forth under the heading "The Series A/B Exchange Offer
-- Withdrawal Rights" on page 33 of this prospectus.
Appraisal or Dissenter's Rights................... Holders of outstanding notes do not have any appraisal or
dissenters' rights in the Series A/B Exchange Offer. If
you do not tender your outstanding notes or Abraxas rejects
your tender, you will not be entitled to any further rights
to exchange your outstanding notes for exchange notes;
however, you may be entitled to certain registration rights
related to a shelf registration statement, in accordance
with the terms of the registration rights agreement. If
you do not tender your notes, they will remain outstanding
and entitled to the benefits of the indenture governing the
notes. You should read the discussion under the heading
"Risk Factors--Risks Related to the Series A/B Exchange
Offer" on page 17 of this prospectus for further
information.
Federal Tax Consequences.......................... The exchange of notes generally is not a taxable exchange
for United States federal income tax purposes. You
generally will not recognize any taxable gain or loss or
any interest income as a result of such exchange. For
additional information regarding the federal tax
consequences of participating in the Series A/B Exchange
Offer and holding the notes, you should read the discussion
under the heading
10
<Page>
"Certain U. S. Federal Income Tax
Considerations."
Exchange Agent.................................... U.S. Bank, N.A. is serving as the exchange agent in the
Series A/B Exchange Offer. The exchange agent's address,
and telephone and facsimile numbers are listed in the
section of this prospectus entitled "The Series A/B
Exchange Offer--Exchange Agent" on page 35 of this
prospectus and in the accompanying letter of transmittal.
Use of Proceeds................................... We will not receive any proceeds from the Series A/B
Exchange Offer, and we will pay the expenses of the
Series A/B Exchange Offer.
</Table>
RISK FACTORS
YOU SHOULD CAREFULLY CONSIDER THE INFORMATION SET FORTH UNDER THE
CAPTION "RISK FACTORS" BEGINNING ON PAGE 17 AND ALL OTHER INFORMATION SET FORTH
IN THIS PROSPECTUS BEFORE DECIDING WHETHER TO PARTICIPATE IN THE SERIES A/B
EXCHANGE OFFER.
SUMMARY OF TERMS OF THE EXCHANGE NOTES
The form and terms of the exchange notes are the same as the form and
terms of the outstanding notes, except that the exchange notes will be
registered under the Securities Act. As a result, the exchange notes will not
bear legends restricting their transfer and will not contain the registration
rights and liquidated damages provisions contained in the outstanding notes,
with certain limited exceptions in accordance with the terms of the registration
rights agreement. The exchange notes represent the same debt as the outstanding
notes. The outstanding notes and the exchange notes are governed by the same
indenture, and we sometimes refer to both series interchangeably as the "notes."
<Table>
Notes................................... Up to $113,439,051 in principal amount of 11 1/2% Secured Notes due
2007, Series B
Issuer.................................. Abraxas Petroleum Corporation
Maturity Date........................... May 1, 2007
Interest Rate and Payment Dates......... The exchange notes will accrue interest from May 1, 2003, at a
fixed annual rate of 11 1/2%, payable in cash semi-annually
on each May 1 and November 1, commencing November 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 for the exchange notes indenture 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, and as
a result we anticipate issuing additional notes on May 1, 2003 as
payment in kind of interest accrued on the notes. 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, Wamsutter, New Grey Wolf, Western Associated
11
<Page>
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
o are subordinated to the indebtedness under the
senior credit agreement;
o rank equally with all of Abraxas' current and
future senior indebtedness; and
o rank senior to all of Abraxas' current and future
subordinated indebtedness, in each case, if any.
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 Exchange Notes--Intercreditor
Agreement" beginning on page 86 of this prospectus.
Collateral.............................. The notes are secured by a second lien or charge on all of our
current and future assets, including 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 the Exchange Notes--Redemption--Optional Redemption" on page 84
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 assets sales, at
the prices described in the sections "Description of the Exchange
Notes--Change of Control" and "--Certain Covenants--Limitation on
Asset Sales" on pages 85 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:
o borrow money or issue preferred stock;
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral
for the notes;
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<Page>
o use assets as security in other transactions;
and
o 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 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.
Form of the Exchange Notes.............. Holders who tender certificated notes in the Series A/B Exchange
Offer will receive exchange notes in certificated form. Exchange
notes issued in exchange for outstanding notes held in book-entry
form through DTC will be represented by one or more permanent
global securities in registered form deposited with U.S. Bank,
N.A., as custodian for Cede & Co., the nominee of DTC, the
book-entry depositary. You will not otherwise receive notes in
certificated form unless one of the events set forth under the
heading "Book-Entry; Delivery and Form" on page 135 of this
prospectus occurs. Instead, beneficial interests in the exchange
notes will be shown on, and transfers of these interests will be
effected only through, records maintained in book-entry form by
DTC with respect to its participants.
Absence of a Public Market
for Exchange Notes.............................. While the outstanding notes are presently eligible for trading in
the Private Offerings, Resales and Trading through Automated
Linkages, or PORTAL, market of the National Association of
Securities Dealers, Inc., or NASD, by qualified institutional
buyers, there is no existing market for the exchange notes.
Jefferies & Company, Inc., the dealer-manager of the exchange
offer, has advised us that it currently intends to make a market
in the exchange notes following the Series A/B Exchange Offer,
but it is not obligated to do so, and any market-making may be
stopped at any time without notice. We do not intend to apply
for a listing of the exchange notes on any securities exchange.
We do not know if an active public market for the notes will
develop or, if developed, will continue. If an active public
market does not develop or is not maintained, the market price
and liquidity of the notes may be adversely affected. We cannot
make any assurances regarding the liquidity of the market for the
exchange notes, the ability of holders to sell their exchange
notes or the price at which holders may sell their exchange notes.
</Table>
For additional information regarding the exchange notes, you should
read the discussion under the heading "Description of the Exchange Notes" on
page 82 of this prospectus.
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<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, from continuing
operations, presented below for each of the three years ended December 31, 2000,
2001 and 2002 has been derived from our consolidated financial statements
included in this prospectus. The pro forma statements of consolidated operations
for the year ended December 31, 2002 , give effect to the exchange offer and
each of the other transactions as if they had occurred on January 1, 2002. The
pro forma balance sheet gives effect to the exchange offer and each of the other
transactions as if they had occurred on December 31, 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.
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
--------------------------------------------
PRO
FORMA
2000 2001 2002 2002
------ ---- ---- -------
(DOLLARS IN THOUSANDS)
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Total operating revenue (1).............. $ 32,886 $ 35,775 $ 22,307 $ 21,241
Lease and other operating expenses (2)... 8,472 10,004 8,477 8,264
Depreciation, depletion and amortization
expense............................... 12,328 12,336 9,654 8,851
Proved property impairment............... -- -- 32,850 32,850
General and administrative expense....... 4,840 4,937 5,082 5,082
Interest expense, net of interest income
(3)................................... 22,317 23,844 24,597 15,408
Amortization of deferred financing fee... 1,660 1,907 1,325 1,724
Income (loss) from continuing operations. $ 9,936 $ (16,043) $(60,846) $(52,106)
Income (loss) from continuing operations
per common share:
Basic.................................. $ 0.43 $ (0.62) $ (2.03) $ (1.46)
Diluted................................ $ 0.31 $ (0.62) $ (2.03) $ (1.46)
OTHER DATA:
Capital expenditures (including
acquisitions)............................ $ 39,767 $ 19,126 $ 15,896 $ 15,896
Ratio of earnings to fixed charges (4)... 1.56X n/a n/a n/a
</Table>
<Table>
<Caption>
DECEMBER 31, 2002
------------------------------
ACTUAL PRO FORMA
------ ---------
(DOLLARS IN THOUSANDS)
CONSOLIDATED BALANCE SHEET DATA:
Total assets........................... $ 181,425 $ 109,643
Total other liabilities................ $ 132,700 $ 7,503
Total debt ............................ $ 190,979 $ 175,298
Stockholders' deficit.................. $ (142,254) $ (73,158)
</Table>
----------
(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.
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<Page>
(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 continuing operations 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 , $15.5 million, $60.8 million, and $52.1
million, respectively. In 2000, we had earnings from continued
operations of $37.4 million and fixed charges of $24.0 million. Our
ratio of earnings to fixed charges during 2000 was 1.56x.
SUMMARY HISTORICAL AND PRO FORMA OPERATING DATA
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-----------------------------------------------
PRO
FORMA
2000 2001 2002 2002
---------- ---- ---- --------
(dollars in thousands, except per unit data)
PRODUCTION:
Crude oil (MBbls).......................... 407 365 265 251
NGLs (MBbls)............................... 132 51 10 9
Natural gas (MMcf)......................... 8,364 7,823 5,680 5,420
Mmcfe.................................... 11,597 10,318 7,324 6,980
AVERAGE SALES PRICE:(1)
Crude oil (per Bbl)........................ $14.01 $ 25.07 $ 24.42 $ 24.95
NGLs (per Bbl)............................. 20.53 15.61 14.88 14.89
Natural gas (per Mcf)...................... 2.84 3.19 2.64 2.61
Per Mcfe................................. 2.77 3.39 2.95 2.94
LOE (PER MCFE)................................ $0.67 $ 0.90 $ 1.08 $ 1.10
</Table>
- ----------
(1) Average sales prices include effects of hedging activities.
15
<Page>
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, 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)............................. 6,081 4,414 3,459 3,459
Natural gas (MMcf)..................................... 114,908 115,668 91,766 91,766
Natural gas equivalents (MMcfe)........................ 151,394 142,152 112,520 112,520
% Proved developed................................... 49% 40% 48% 48 %
Estimated future net revenue before income taxes.......$ 954,783 $ 175,344 $ 276,746 $ 276,746
PV-10.................................................. 486,120 77,187 136,584 136,584
% Proved developed................................... 47% 63% 65% 65%
</Table>
16
<Page>
RISK FACTORS
YOU SHOULD CAREFULLY CONSIDER THE FOLLOWING RISK FACTORS IN ADDITION TO
THE OTHER INFORMATION IN THIS PROSPECTUS BEFORE MAKING A DECISION TO EXCHANGE
YOUR OUTSTANDING NOTES IN THE SERIES A/B EXCHANGE OFFER.
RISKS RELATED TO THE SERIES A/B EXCHANGE OFFER
IF YOU DO NOT EXCHANGE YOUR OUTSTANDING NOTES, THEY MAY BE DIFFICULT TO
RESELL. If the holders of the outstanding notes do not exchange their notes in
the Series A/B Exchange Offer, they may be able to rely on a shelf registration
statement to have an offering of such outstanding notes registered under the
Securities Act, subject to certain limitations. However, a holder of such
outstanding notes after the Series A/B Exchange Offer is consummated may be
unable to freely sell the notes, if such shelf registration statement is not
declared effective or if such effectiveness is suspended. Without the benefit of
an effective shelf registration statement, it may be difficult for you to freely
sell the outstanding notes that are not exchanged in the Series A/B Exchange
Offer, since any outstanding notes not exchanged will remain subject to the
restrictions on transfer provided for under the Securities Act. These
restrictions on transfer of your outstanding notes exist because we issued the
outstanding notes pursuant to an exemption from the registration requirements of
the Securities Act and applicable state securities laws.
Generally, the outstanding notes that are not exchanged for the
exchange notes pursuant to the Series A/B Exchange Offer and are not part of a
registered offering in connection with a shelf registration statement, together
with any additional notes issued as payment in kind of interest on these notes,
will remain restricted securities. Accordingly, any such outstanding notes may
be resold only:
o to us (upon redemption of the notes or otherwise);
o pursuant to an effective registration statement under the
Securities Act;
o so long as the notes are eligible for resale pursuant to Rule
144A under the Securities Act to a qualified institutional
buyer within the meaning of Rule 144A in a transaction meeting
the requirements of Rule 144A;
o outside the United States to a foreign person pursuant to the
exemption from the registration requirements of the Securities
Act provided by Regulation S under the Securities Act;
o pursuant to an exemption from registration under the
Securities Act provided by Rule 144 thereunder (if available);
or
o pursuant to another available exemption from the registration
requirements of the Securities Act, in each case in accordance
with any applicable securities laws of any state of the United
States.
To the extent any outstanding notes are tendered and accepted in the
Series A/B Exchange Offer, the trading market, if any, for the outstanding notes
that remain outstanding after the Series A/B Exchange Offer is completed would
be adversely affected due to a reduction in market liquidity.
IF YOU DO NOT EXCHANGE YOUR OUTSTANDING NOTES, YOU WILL HAVE NO FURTHER
REMEDIES UNDER THE SERIES A/B EXCHANGE OFFER. Any liquidated damages payable to
such a holder of outstanding notes will only arise as a result of a registration
default relating to a shelf registration statement and such a holder will have
no further remedies pursuant to the Series A/B Exchange Offer.
THERE IS CURRENTLY NO ACTIVE TRADING MARKET FOR THE EXCHANGE NOTES, THE
VALUE OF THE EXCHANGE NOTES MAY FLUCTUATE SIGNIFICANTLY AND ANY MARKET FOR THE
EXCHANGE NOTES MAY BE ILLIQUID. Although upon the completion of the Series A/B
Exchange Offer the exchange notes will generally be freely transferable, there
is currently no public market for the exchange notes. We have been informed by
Jefferies & Company, Inc. that it intends to make a market in the exchange notes
after the Series A/B Exchange Offer is completed. However, Jefferies may cease
its market-making at any time. In addition, the liquidity of the trading market
in the exchange notes, and the market price quoted for these notes, may be
adversely affected by changes in the overall market for high yield securities
and by changes in our financial performance or prospects or in the prospects for
companies in our industry, generally. As a result, you cannot be sure that an
active trading market will develop for the exchange notes. If no active
17
<Page>
trading market develops, you may not be able to resell your exchange notes at
their fair market value or at all, even though they are freely transferable.
RISKS RELATED TO THE NOTES
THE SECURITY FOR THE NOTES MAY BE INADEQUATE TO SATISFY ALL AMOUNTS DUE
AND OWING TO OUR SENIOR SECURED CREDITORS AND 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 Exchange
Notes--Security" on page 85 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
o was insolvent or rendered insolvent by reason of the
issuance of the guarantee;
o was engaged or about to engage in a business or
transaction for which the remaining assets of the
guarantor constituted unreasonably small capital; or
o 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.
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
18
<Page>
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:
o a transfer of the debtor's property;
o to or for the benefit of a creditor on account of an
existing debt;
o made while the debtor was insolvent (presumed in the
90 days before a bankruptcy filing);
o if the creditor receives more than it would have
received in a bankruptcy liquidation if the transfer
had not been made; and
o 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.
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 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
19
<Page>
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
129 of this prospectus.
THE AMOUNT OF ANY CLAIM MADE BY YOU 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:
o the initial issue price for the notes; and
o 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. 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.
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.
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,
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<Page>
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:
o 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;
o 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
o 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 Exchange 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 97 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.
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 41.
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<Page>
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:
o production being less than expected; or
o 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, of which $14.0 million, $6.6
million and $1.5 million, respectively, were applicable to continuing
operations.
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, $167.1 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, some 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.
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 ($32.9 million for continuing operations and $83.1
million for discontinued operations). 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:
o changes in supply and demand for crude oil and natural gas;
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<Page>
o weather conditions;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
especially those in the Middle East; and
o 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:
o reducing the overall volumes of crude oil and natural
gas that we can produce economically;
o causing a ceiling limitation write-down;
o increasing our dependence on external sources of
capital to meet our liquidity requirements; and
o 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 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.
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<Page>
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 $50.4 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 from continuing operations:
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
---------------------------------------------
1998 1999 2001 2002
---- ---- ---- ----
Net (loss) from continuing
operations $(79.0) $(24.4) $(16.0) $ (60.8)
</Table>
While we had net income in 2000 of $9.9 million from continuing operations, if
the significant gain on the sale of an interest in a partnership were excluded,
we would have experienced a net loss from continuing operations for the year of
$(24.1) 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 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.
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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:
o that no commercially productive crude oil or natural
gas reservoirs will be found;
o that crude oil and natural gas drilling and
production activities may be shortened, delayed or
canceled; and
o that our ability to develop, produce and market our
reserves may be limited by:
o title problems,
o weather conditions,
o compliance with governmental requirements,
and
o 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 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
25
<Page>
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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USE OF PROCEEDS
Abraxas will not receive any proceeds from the Series A/B Exchange
Offer.
RATIO OF EARNINGS TO FIXED CHARGES
Earnings consist of income from continuing operations 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 $79.0 million, $24.2 million, $15.5 million, $60.8 million
and $52.1 million, respectively. In 2000, we had earnings from continued
operations of $37.4 million and fixed charges of $24.0 million. Our ratio of
earnings to fixed charges during 2000 was 1.56x.
CAPITALIZATION
The following table sets forth our cash position and total
consolidated capitalization at December 31, 2002, on a historical and pro
forma basis.
<Table>
<Caption>
DECEMBER 31, 2002
HISTORICAL PRO FORMA (1)
-------------- --------------
(DOLLARS IN THOUSANDS)
Cash....................................................... $ 557 $ 557
============== ==============
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 --
New Senior Credit Agreement.............................. -- 46,700
11 1/2% Secured Notes due 2007 (new notes) (2)........... -- 128,598
-------------- --------------
Total debt....................................... 254,479 175,298
Stockholders' equity (deficit)............................. (142,254) (73,158)
-------------- --------------
Total capitalization..................................... $ 112,225 $ 102,140
============== ==============
</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 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.
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<Page>
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC set forth in
no-action letters issued to third parties in similar transactions, we believe
that the exchange notes issued in the Series A/B Exchange Offer in exchange
for the outstanding notes may be offered for resale, resold and otherwise
transferred by holders without compliance with the registration and
prospectus delivery provisions of the Securities Act, provided that the
exchange notes are acquired in the ordinary course of such holders' business
and the holders are not engaged in, and do not intend to engage in, and have
no arrangement or understanding with any person to participate in, a
distribution of exchange notes. This position does not apply to any holder
that is (1) an "affiliate" of Abraxas within the meaning of Rule 405 under
the Securities Act, (2) a broker-dealer who acquired exchange notes directly
from Abraxas or (3) broker-dealers who acquired exchange notes as a result of
market-making or other trading activities. Any broker-dealers or
participating broker-dealers receiving exchange notes in the Series A/B
Exchange Offer are subject to a prospectus delivery requirement with respect
to resales of the exchange notes. To date, the SEC has taken the position
that participating broker-dealers may, for a limited period, fulfill their
prospectus delivery requirements with respect to transactions involving an
exchange of securities such as the exchange notes pursuant to the Series A/B
Exchange Offer with this prospectus.
Each broker-dealer receiving exchange notes for its own account in
the Series A/B Exchange Offer must acknowledge that it will deliver a
prospectus in any resale of the exchange notes. Participating broker-dealers
may use this prospectus in reselling exchange notes, if the outstanding notes
were acquired for their own accounts as a result of market-making activities
or other trading activities. Abraxas has agreed that a participating
broker-dealer may use this prospectus in reselling exchange notes for a
period ending 180 days after the expiration time or, if earlier, when a
participating broker-dealer has disposed of all exchange notes. A
participating broker-dealer intending to use this prospectus in the resale of
exchange notes must notify Abraxas, on or before the expiration time, that it
is a participating broker-dealer. This notice may be given in the space
provided in the letter of transmittal or may be delivered to the exchange
agent. Abraxas has agreed that, for a period of 180 days after the expiration
time, it will make this prospectus, and any amendment or supplement to this
prospectus, available to any broker-dealer that so requests these documents.
See "The Series A/B Exchange Offer--Resales of Exchange Notes" on page 33 of
this prospectus for more information.
Abraxas will not receive any cash proceeds from any sale of the
exchange notes by broker-dealers. Broker-dealers acquiring exchange notes for
their own accounts may sell the notes in one or more transactions in the
over-the-counter market, in negotiated transactions, through writing options
on the exchange notes or a combination of such methods. Any resale may be
made directly to purchasers or to or through brokers or dealers who may
receive compensation in the form of commissions or concessions from any
broker-dealer and/or the purchasers of exchange notes.
Any broker-dealer reselling exchange notes that it received in the
Series A/B Exchange Offer and any broker or dealer that participates in a
distribution of exchange notes may be deemed to be an "underwriter" within
the meaning of the Securities Act. Any profit on any resale of exchange notes
and any commissions or concessions received by any persons may be deemed to
be underwriting compensation under the Securities Act. The letter of
transmittal states that by acknowledging that it will deliver and by
delivering a prospectus, a dealer-broker will not admit that it is an
"underwriter" within the meaning of the Securities Act.
THE SERIES A/B EXCHANGE OFFER
PURPOSE OF THE SERIES A/B EXCHANGE OFFER
Abraxas issued $109,706,000 of the outstanding notes in a private
exchange offer on January 23, 2003, pursuant to the terms and conditions of
an Offer to Exchange, dated as of December 9, 2002, as thereafter
supplemented and amended, and Abraxas anticipates issuing an additional
principal amount of $3,733,051 of these notes on May 1, 2003 as payment of
interest in kind on the outstanding notes. In connection with the exchange
offer, we agreed in the registration rights agreement to conduct the Series
A/B Exchange Offer.
The form and terms of the exchange notes are the same as the form
and terms of the outstanding notes, except that the offering of the exchange
notes will be registered under the Securities Act, and holders of the
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<Page>
exchange notes will not be entitled to liquidated damages except in certain
limited circumstances in accordance with the terms of the registration rights
agreement.
SERIES A/B EXCHANGE OFFER REGISTRATION STATEMENT
The registration rights agreement requires us to:
o file a registration statement with respect to an offer to exchange the
outstanding notes for the exchange notes, which would have terms
substantially identical in all material respects to the outstanding
notes with the SEC by February 7, 2003;
o use our reasonable best efforts to cause such exchange offer
registration statement to become effective under the Securities Act by
May 8, 2003; and
o use our reasonable best efforts to keep the exchange offer registration
statement effective continuously for the minimum period required for
the consummation of the Series A/B Exchange Offer pursuant to its
terms.
Abraxas has agreed to keep the Series A/B Exchange Offer open for
not less than 20 days, or longer if required by applicable law, after the
date notice thereof is mailed to the holders of outstanding notes.
SHELF REGISTRATION STATEMENT
The registration rights agreement also requires us to:
o file a shelf registration statement with respect to the resale of the
outstanding notes and shares of Abraxas common stock issued in the
January 2003 private exchange offer with the SEC by February 7, 2003;
and
o use our reasonable best efforts to cause such registration statement to
become effective under the Securities Act by May 8, 2003.
Abraxas has agreed to use its reasonable best efforts to keep the shelf
registration statement effective until January 23, 2005, subject to certain
exceptions described in the registration rights agreement.
LIQUIDATED DAMAGES
The registration rights agreement requires Abraxas to pay liquidated
damages to the holders of the notes if:
o either the exchange offer registration statement or the shelf
registration statement has not been filed with the SEC by February 7,
2003;
o either the exchange offer registration statement or the shelf
registration statement has not been declared effective by the SEC by
May 8, 2003; or
o any registration statement is filed and declared effective by the SEC
but thereafter ceases to be effective or usable in connection with
resales of such securities during the periods specified in the
registration rights agreement.
Abraxas filed both registration statements with the SEC on February 7,
2003, and the SEC declared each of them effective on April __, 2003. Upon the
occurrence of the registration default described in the third bullet point
above, the interest rate on the outstanding notes or exchange notes, as
applicable, 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 registration default 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 registration defaults have been cured, up to a maximum per annum interest
rate on such notes of 18% with respect to all registration defaults. All accrued
liquidated damages will be paid by Abraxas in the same manner and at the same
time as payments of interest on the outstanding notes or exchange notes, as
applicable, and any additional notes issued in lieu of cash interest payments.
Following the cure of all registration defaults, the accrual of liquidated
damages will cease. No liquidated damages will be payable to holders of the
common stock who do not otherwise hold outstanding notes or exchange notes, as
applicable.
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<Page>
Upon the completion of the Series A/B Exchange Offer, holders of
outstanding notes will not be entitled to any liquidated damages on the
outstanding notes unless there is a registration default related to the shelf
registration statement. See "Risk Factors--Risks Related to the Series A/B
Exchange Offer" and "Description of the Exchange Notes" for further
information regarding the rights of holders of outstanding notes after the
Series A/B Exchange Offer. The Series A/B Exchange Offer is not extended to
holders of outstanding notes in any jurisdiction where the Series A/B
Exchange Offer does not comply with the securities or blue sky laws of that
jurisdiction.
The term "holder" as used in this section of the prospectus entitled
"The Series A/B Exchange Offer" means (1) any person in whose name the
outstanding notes are registered on the books of Abraxas, or (2) any other
person who has obtained a properly completed bond power from the registered
holder, or (3) any person whose outstanding notes are held of record by DTC
and who wants to deliver such outstanding notes by book-entry transfer at DTC.
TERMS OF THE SERIES A/B EXCHANGE OFFER
We are offering to exchange up to $113,439,051 total principal
amount of exchange notes for a like total principal amount of outstanding
notes. The outstanding notes must be tendered properly on or before the
expiration time and not withdrawn. In exchange for outstanding notes properly
tendered and accepted, we will issue a like total principal amount of up to
$113,439,051 in exchange notes.
The Series A/B Exchange Offer is not conditioned upon holders
tendering a minimum principal amount of outstanding notes. As of the date of
this prospectus, $109,706,000 aggregate principal amount of outstanding notes
are outstanding, but Abraxas anticipates issuing an additional $3,733,051
aggregate principal amount of these notes as payment of interest on the
outstanding notes due on May 1, 2003.
Holders of the outstanding notes do not have any appraisal or
dissenters' rights in the Series A/B Exchange Offer. If holders do not tender
outstanding notes or tender outstanding notes that Abraxas does not accept,
their outstanding notes will remain outstanding. Any outstanding notes will
be entitled to the benefits of the indenture, and will be entitled to the
further registration rights described in the registration rights agreement.
See "Risk Factors--Risks Related to the Series A/B Exchange Offer" on page 17
of this prospectus for further information regarding the rights of holders of
outstanding notes after the Series A/B Exchange Offer.
After the expiration time, Abraxas will return to the holder any
tendered outstanding notes that Abraxas did not accept for exchange.
Holders exchanging outstanding notes will not have to pay brokerage
commissions or fees or transfer taxes if they follow the instructions in the
letter of transmittal. Abraxas will pay the charges and expenses, other than
certain taxes described below, in the Series A/B Exchange Offer. See "--Fees
and Expenses" for further information regarding fees and expenses.
NEITHER ABRAXAS NOR ITS BOARD OF DIRECTORS RECOMMENDS YOU TO TENDER
OR NOT TENDER OUTSTANDING NOTES IN THE SERIES A/B EXCHANGE OFFER. IN
ADDITION, ABRAXAS HAS NOT AUTHORIZED ANYONE TO MAKE ANY RECOMMENDATION. YOU
MUST DECIDE WHETHER TO TENDER IN THE SERIES A/B EXCHANGE OFFER AND, IF SO,
THE AGGREGATE AMOUNT OF OUTSTANDING NOTES TO TENDER.
The expiration time is Midnight, New York City time, on
_____________, 2003, unless Abraxas extends the Series A/B Exchange Offer.
Abraxas has the right, in accordance with applicable law, at any
time:
o to delay the acceptance of the outstanding notes;
o to terminate the Series A/B Exchange Offer if Abraxas determines
that any of the conditions to the Series A/B Exchange Offer have
not occurred or have not been satisfied;
o to extend the expiration time of the Series A/B Exchange Offer and
keep all outstanding notes tendered other than those notes properly
withdrawn; and
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<Page>
o to waive any condition or amend the terms of the Series A/B
Exchange Offer.
If Abraxas materially changes the Series A/B Exchange Offer, or if
Abraxas waives a material condition of the Series A/B Exchange Offer, Abraxas
will promptly distribute a prospectus supplement to the holders of the
outstanding notes disclosing the change or waiver. Abraxas also will extend
the Series A/B Exchange Offer as required by Rule 14e-1 under the Securities
Exchange Act of 1934, as amended.
If Abraxas exercises any of the rights listed above, it will
promptly give oral or written notice of the action to the exchange agent and
will issue a release to an appropriate news agency. In the case of an
extension, an announcement will be made no later than 9:00 a.m., New York
City time, on the next business day after the previously scheduled expiration
time.
ACCEPTANCE FOR EXCHANGE AND ISSUANCE OF EXCHANGE NOTES
Promptly after the expiration time, Abraxas will issue exchange
notes for outstanding notes tendered and accepted and not withdrawn. Delivery
of the exchange notes issued in global form will occur through the facilities
of DTC, and the exchange agent will deliver the exchange notes issued in
certificated form. If a tendering noteholder tenders certificated notes, the
exchange agent might not deliver the exchange notes to all of such tendering
holders at the same time. The timing of delivery depends upon when the
exchange agent receives and processes the required documents.
Abraxas will be deemed to have exchanged outstanding notes validly
tendered and not withdrawn when Abraxas gives oral or written notice to the
exchange agent of their acceptance. The exchange agent is an agent for
Abraxas for receiving tenders of outstanding notes, letters of transmittal
and related documents. The exchange agent is also an agent for tendering
holders for these same purposes, and in the case of holders who tender
certificated notes, the exchange agent is also their agent for the delivery
of their exchange notes. If for any reason, Abraxas (1) delays the acceptance
or exchange of any outstanding notes; (2) extends the Series A/B Exchange
Offer; or (3) is unable to accept or exchange outstanding notes, then the
exchange agent may, on behalf of Abraxas and subject to Rule 14e-1(c) under
the Exchange Act, retain tendered notes. Notes retained by the Exchange Agent
may not be withdrawn, except according to the withdrawal procedures outlined
in the section entitled "--Withdrawal Rights" below.
In tendering outstanding notes, you must warrant in the letter of
transmittal or in an agent's message (described below) that:
o you have full power and authority to tender, exchange, sell,
assign and transfer outstanding notes;
o Abraxas will acquire good, marketable and unencumbered title
to the tendered outstanding notes, free and clear of all
liens, restrictions, charges and other encumbrances; and
o the outstanding notes tendered for exchange are not subject to
any adverse claims, rights or proxies.
You also must warrant and agree that you will, upon request, execute
and deliver any additional documents requested by Abraxas or the exchange
agent to complete the exchange, sale, assignment and transfer of the
outstanding notes.
PROCEDURES FOR TENDERING OUTSTANDING NOTES
VALID TENDER
You may tender your outstanding notes by book-entry transfer or by
other means. For book-entry transfer, (1) you must deliver to the exchange agent
either a completed and signed letter of transmittal or (2) DTC must deliver an
agent's message, meaning a message transmitted to the exchange agent by DTC
stating that you agree to be bound by the terms of the letter of transmittal.
You must deliver your letter of transmittal by mail, facsimile, hand delivery or
overnight courier or DTC must deliver the agent's message to the exchange agent
on or before the expiration time. In addition, to complete a book-entry
transfer, you must also either (1) have DTC transfer the outstanding notes into
the exchange agent's account at DTC using the ATOP procedures for transfer, and
obtain a confirmation of such a transfer, or (2) follow the guaranteed delivery
procedures described below under "--Guaranteed Delivery Procedures."
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If you tender fewer than all of your outstanding notes, you should
fill in the amount of notes tendered in the appropriate box on the letter of
transmittal. If you do not indicate the amount tendered in the appropriate
box, Abraxas will assume you are tendering all outstanding notes that you
hold.
To tender certificated outstanding notes or to otherwise tender your
outstanding notes other than by book-entry transfer, you must deliver a
completed and signed letter of transmittal to the exchange agent. Again, you
must deliver the letter of transmittal by mail, facsimile, hand delivery or
overnight courier to the exchange agent on or before the expiration time. In
addition, to complete a valid tender, you must either (1) deliver your
outstanding notes to the exchange agent on or before the expiration time, or
(2) follow the guaranteed delivery procedures set forth below under
"--Guaranteed Delivery Procedures."
DELIVERY OF REQUIRED DOCUMENTS BY WHATEVER METHOD YOU CHOOSE IS AT
YOUR SOLE RISK. DELIVERY IS COMPLETE WHEN THE EXCHANGE AGENT ACTUALLY
RECEIVES THE ITEMS TO BE DELIVERED. DELIVERY OF DOCUMENTS TO DTC IN
ACCORDANCE WITH DTC'S PROCEDURES DOES NOT CONSTITUTE DELIVERY TO THE EXCHANGE
AGENT. IF DELIVERY IS BY MAIL, THEN REGISTERED MAIL, RETURN RECEIPT
REQUESTED, PROPERLY INSURED, OR AN OVERNIGHT DELIVERY SERVICE IS RECOMMENDED.
IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ENSURE TIMELY DELIVERY.
SIGNATURE GUARANTEES
You do not need to endorse certificates for the outstanding notes or
provide signature guarantees on the letter of transmittal, unless (a) someone
other than the registered holder tenders the certificate or (b) you complete
the box entitled "Special Issuance Instructions" or "Special Delivery
Instructions" in the letter of transmittal. In the case of (a) or (b) above,
you must sign your outstanding notes or provide a properly executed bond
power, with the signature on the bond power and on the letter of transmittal
guaranteed by a firm or other entity identified in Rule 17Ad-15 under the
Exchange Act as an "eligible guarantor institution." Eligible guarantor
institutions include: (1) a bank; (2) a broker, dealer, municipal securities
broker or dealer or government securities broker or dealer; (3) a credit
union; (4) a national securities exchange, registered securities association
or clearing agency; or (5) a savings association that is a participant in a
securities transfer association.
GUARANTEED DELIVERY PROCEDURES
If you want to tender your outstanding notes in the Series A/B
Exchange Offer and (1) the certificates for the outstanding notes are not
lost but are not immediately available, (2) all required documents are
unlikely to reach the exchange agent on or before the expiration time, or (3)
a book-entry transfer cannot be completed in time, you may tender your
outstanding notes if you comply with the following guaranteed delivery
procedures:
o the tender is made by or through an eligible guarantor institution;
o you deliver a properly completed and signed notice of guaranteed
delivery, similar to the form provided with the letter of transmittal,
to the exchange agent on or before the expiration time; and
o you deliver the certificates or a confirmation of book-entry transfer
and a properly completed and signed letter of transmittal to the
exchange agent within three New York Stock Exchange trading days after
the notice of guaranteed delivery is executed.
You may deliver the notice of guaranteed delivery by hand, facsimile
or mail to the exchange agent and must include a guarantee by an eligible
guarantor institution in the form described in the notice.
Abraxas' acceptance of properly tendered outstanding notes is a
binding agreement between the tendering holder and Abraxas upon the terms and
subject to the conditions of the Series A/B Exchange Offer.
DETERMINATION OF VALIDITY
Abraxas will resolve all questions regarding the form of documents,
validity, eligibility (including time of receipt) and acceptance for exchange
of any tendered outstanding notes. Abraxas' resolution of these questions as
well as Abraxas' interpretation of the terms and conditions of the Series A/B
Exchange Offer (including the letter of
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<Page>
transmittal) is final and binding on all parties. A tender of outstanding
notes is invalid until all irregularities have been cured or waived. Neither
Abraxas, any affiliates or assigns of Abraxas, the exchange agent nor any
other person is under any obligation to give notice of any irregularities in
tenders nor will they be liable for failing to give any such notice. Abraxas
reserves the absolute right, in its sole and absolute discretion, to reject
any tenders determined to be in improper form or unlawful. Abraxas also
reserves the absolute right to waive any of the conditions of the Series A/B
Exchange Offer or any condition or irregularity in the tender of outstanding
notes by any holder. Abraxas need not waive similar conditions or
irregularities in the case of other holders.
If any letter of transmittal, endorsement, bond power, power of
attorney, or any other document required by the letter of transmittal is
signed by a trustee, executor, administrator, guardian, attorney-in-fact,
officer of a corporation or other person acting in a fiduciary or
representative capacity, that person must indicate that capacity when
signing. In addition, unless waived by Abraxas, the person must submit proper
evidence satisfactory to Abraxas, in its sole discretion, of his or her
authority to so act.
A beneficial owner of outstanding notes that are held by or
registered in the name of a broker, dealer, commercial bank, trust company or
other nominee or custodian should contact that entity promptly if the holder
wants to participate in the Series A/B Exchange Offer.
WITHDRAWAL RIGHTS
You can withdraw tenders of outstanding notes at any time on or
before the expiration time.
For a withdrawal to be effective, you must deliver a written,
telegraphic, telex or facsimile transmission of a notice of withdrawal to the
exchange agent on or before the expiration time. The notice of withdrawal
must specify the name of the person tendering the outstanding notes to be
withdrawn, the total principal amount of outstanding notes withdrawn, and the
name of the registered holder of the outstanding notes if different from the
person tendering the outstanding notes. If you delivered outstanding notes to
the exchange agent in certificated form, you must submit the serial numbers
of the outstanding notes to be withdrawn and the signature on the notice of
withdrawal must be guaranteed by an eligible guarantor institution, except in
the case of outstanding notes tendered for the account of an eligible
guarantor institution. If you tendered outstanding notes as a book-entry
transfer, the notice of withdrawal must specify the name and number of the
account at DTC to be credited with the withdrawal of outstanding notes and
you must deliver the notice of withdrawal to the exchange agent by written,
telegraphic, telex or facsimile transmission. You may not rescind withdrawals
of tender. Outstanding notes properly withdrawn may again be tendered at any
time on or before the expiration time.
Abraxas will determine all questions regarding the validity, form
and eligibility of withdrawal notices. Abraxas' determination will be final
and binding on all parties. Neither Abraxas, any affiliate or assign of
Abraxas, the exchange agent nor any other person is under any obligation to
give notice of any irregularities in any notice of withdrawal, nor will they
be liable for failing to give any such notice. Withdrawn outstanding notes
will be returned to the holder after withdrawal.
RESALES OF EXCHANGE NOTES
Abraxas is exchanging the outstanding notes for exchange notes based
upon the position of the SEC staff set forth in interpretive letters to third
parties in other similar transactions. Abraxas will not seek its own
interpretive letter, unless contractually required to in accordance with the
terms of the registration rights agreement. As a result, Abraxas cannot
assure you that the SEC staff will take the same position on the Series A/B
Exchange Offer as it did in interpretive letters to other parties. Based on
the SEC staff's letters to other parties, Abraxas believes that holders of
exchange notes, other than broker-dealers, can offer the notes for resale,
resell and otherwise transfer the exchange notes without delivering a
prospectus to prospective purchasers. However, prospective holders must
acquire the exchange notes in the ordinary course of business and have no
intention of engaging in a distribution of the notes, as a "distribution" is
defined by the Securities Act.
Any holder of outstanding notes who is an "affiliate" of Abraxas or
who intends to distribute exchange notes, or any broker-dealer who purchased
outstanding notes from Abraxas for resale pursuant to Rule 144A or any other
available exemption under the Securities Act:
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o cannot rely on the SEC staff's interpretations in the
above-mentioned interpretive letters;
o cannot tender outstanding notes in the Series A/B Exchange Offer;
and
o must comply with the registration and prospectus delivery
requirements of the Securities Act to transfer the outstanding
notes, unless the sale is exempt.
In addition, if any broker-dealer acquired outstanding notes for its
own account as a result of market-making or other trading activities and
exchanges the outstanding notes for exchange notes, the broker-dealer must
deliver a prospectus with any resales of the exchange notes.
If you want to exchange your outstanding notes for exchange notes, you
will be required to affirm that:
o you are not an "affiliate" of Abraxas;
o you are acquiring the exchange notes in the ordinary course of
your business;
o you have no arrangement or understanding with any person to
participate in a distribution of the exchange notes (within
the meaning of the Securities Act); and
o you are not a broker-dealer, not engaged in, and do not intend
to engage in, a distribution of the exchange notes (within the
meaning of the Securities Act).
In addition, Abraxas may require you to provide information
regarding the number of "beneficial owners" (within the meaning of Rule 13d-3
under the Exchange Act) of the outstanding notes. Each broker-dealer that
receives exchange notes for its own account must acknowledge that it acquired
the outstanding notes for its own account as the result of market-making
activities or other trading activities and must agree that it will deliver a
prospectus meeting the requirements of the Securities Act in connection with
any resale of exchange notes. By making this acknowledgment and by delivering
a prospectus, a broker-dealer will not be deemed to admit that it is an
"underwriter" under the Securities Act. Based on the SEC staff's position in
certain interpretive letters, Abraxas believes that broker-dealers who
acquired outstanding notes for their own accounts as a result of
market-making activities or other trading activities may fulfill their
prospectus delivery requirements with respect to the exchange notes with a
prospectus meeting the requirements of the Securities Act. Accordingly, a
broker-dealer may use this prospectus to satisfy such requirements. Abraxas
has agreed that a broker-dealer may use this prospectus for a period ending
180 days after the expiration time or, if earlier, when a broker-dealer has
disposed of all exchange notes. See "Plan of Distribution" for further
information. A broker-dealer intending to use this prospectus in the resale
of exchange notes must notify Abraxas, on or prior to the expiration time,
that it is a participating broker-dealer (as described in "Plan of
Distribution"). This notice may be given in the letter of transmittal or may
be delivered to the exchange agent. Any participating broker-dealer who is an
"affiliate" of Abraxas may not rely on the SEC staff's interpretive letters
and must comply with the registration and prospectus delivery requirements of
the Securities Act when reselling exchange notes.
INTEREST ON THE EXCHANGE NOTES
The exchange notes will accrue interest from May 1, 2003, at 11 1/2%,
payable in cash semi-annually, on each May 1 and November 1, commencing
November 1, 2003 PROVIDED THAT, if we fail, or are not permitted pursuant to
the new senior credit agreement or an intercreditor agreement, to make such
cash interest payments in full, we will pay such unpaid interest by the
issuance of additional notes with a principal amount equal to the amount of
accrued and unpaid cash interest on the exchange notes plus an additional 1%
accrued interest for the applicable period. The exchange notes will, upon an
event of default, accrue interest at an annual rate of 16.5%.
CONDITIONS TO THE SERIES A/B EXCHANGE OFFER
Abraxas need not exchange any outstanding notes, may terminate the
Series A/B Exchange Offer or may waive any conditions to the Series A/B
Exchange Offer or amend the Series A/B Exchange Offer, if any of the
following conditions have occurred:
o the SEC staff no longer allows the exchange notes to be
offered for resale, resold and otherwise transferred by
certain holders without compliance with the registration and
prospectus delivery provisions of the Securities Act;
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<Page>
o a governmental body passes any law, statute, rule or regulation
which, in Abraxas' opinion, prohibits or prevents the Series A/B
Exchange Offer;
o the SEC or any state securities authority issues a stop order
suspending the effectiveness of the registration statement or
initiates or threatens to initiate a proceeding to suspend the
effectiveness of the registration statement; or
o Abraxas is unable to obtain any governmental approval that Abraxas
believes is necessary to complete the Series A/B Exchange Offer.
If Abraxas reasonably believes that any of the above conditions has
occurred, it may (1) terminate the Series A/B Exchange Offer, whether or not
any outstanding notes have been accepted for exchange, (2) waive any
condition to the Series A/B Exchange Offer or (3) amend the terms of the
Series A/B Exchange Offer in any respect subject to Abraxas' contractual
obligation in the registration rights agreement to seek a no-action letter or
other favorable decision from the SEC that would permit the consummation of
the Series A/B Exchange Offer. If Abraxas' waiver or amendment materially
changes the Series A/B Exchange Offer, Abraxas will promptly disclose the
waiver or amendment through a prospectus supplement, distributed to the
registered holders of the outstanding notes. The prospectus supplement also
will extend the Series A/B Exchange Offer as required by Rule 14e-1 of the
Exchange Act.
EXCHANGE AGENT
Abraxas has appointed U.S. Bank, N.A. as exchange agent for the Series
A/B Exchange Offer. Holders should direct questions and requests for assistance,
requests for additional copies of this prospectus or of the letter of
transmittal and requests for notice of guaranteed delivery to the exchange agent
addressed as follows:
<Table>
<Caption>
BY REGISTERED OR CERTIFIED MAIL: REGULAR MAIL, COURIERS OR BY HAND
DELIVERY: BY FACSIMILE:
U.S. Bank, N.A. U.S. Bank, N.A. (651) 244-0711
180 East Fifth Street 180 East Fifth Street (For Eligible Institutions Only)
Saint Paul, MN 55101 Saint Paul, MN 55101
Attn.: Frank Leslie Attn.: Frank Leslie
Corporate Trust Services Corporate Trust Services
</Table>
If you deliver letters of transmittal or any other required
documents to an address or facsimile number other than those listed above,
your tender is invalid.
FEES AND EXPENSES
Abraxas will pay the exchange agent reasonable and customary fees
for its services and reasonable out-of-pocket expenses. Abraxas also will pay
brokerage houses and other custodians, nominees and fiduciaries their
reasonable out-of-pocket expenses for sending copies of this prospectus and
related documents to holders of outstanding notes, and in handling or
tendering for their customers.
Abraxas will pay the transfer taxes for the exchange of the
outstanding notes in the Series A/B Exchange Offer. If, however, exchange
notes are delivered to or issued in the name of a person other than the
registered holder, or if a transfer tax is imposed for any reason other than
for the exchange of outstanding notes in the Series A/B Exchange Offer, then
the tendering holder will pay the transfer taxes. If a tendering holder does
not submit satisfactory evidence of payment of taxes or exemption from taxes
with the letter of transmittal, the taxes will be billed directly to the
tendering holder.
Abraxas will not make any payment to brokers, dealers or other
nominees soliciting acceptances in the Series A/B Exchange Offer.
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ACCOUNTING TREATMENT
The exchange notes will be recorded at the same carrying value as
the outstanding notes. Accordingly, no gain or loss for accounting purposes
will be recognized by upon the closing of the Series A/B Exchange Offer.
Costs associated with the Series A/B Exchange Offer will be expensed as
incurred.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Unaudited Pro Forma Condensed Consolidated Balance Sheet of
Abraxas as of December 31, 2002 has been prepared assuming that the exchange
offer and each of the other transactions described under "Business--Recent
Developments--Financial Restructuring" were consummated on December 31, 2002.
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 and the repurchase of a production payment which occurred in
the second quarter of 2002 (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 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. There are no operating income
adjustments for the divestiture of Canadian operations since these amounts
were included in discontinued operations in the Company's 2002 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.
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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... $ 21,601 $ (1,066)(1) $ $ 20,535
Rig revenues...................... 635 -- 635
Other............................. 71 -- -- 71
---------- ----------- ------------ -----------
Total revenues............. 22,307 (1,066) -- 21,241
Operating costs and expenses:
Lease operating and production
taxes........................... 7,910 (213)(1) -- 7,697
Depreciation, depletion and
amortization.................... 9,654 (803)(1) 8,851
Proved property impairment........ 32,850 -- -- 32,850
Rig operations.................... 567 -- -- 567
General and administrative........ 5,082 -- -- 5,082
---------- ----------- ------------ -----------
Total operating expenses... 56,063 (1,016) -- 55,047
---------- ----------- ------------ -----------
Operating income (loss) from
continuing operations............... (33,756) (50) -- (33,806)
Other (income) expense:
Interest income................... (92) -- -- (92)
Amortization of deferred (1,325)(3)
financing fees.................. 1,325 -- 1,724 (3) 1,724
Interest expense.................. (24,085)(3)
24,689 (604)(2) 15,500 (3) 15,500
Financing costs................... 967 -- -- 967
Other............................. 201 -- -- 201
----------- ----------- ------------ -----------
Income (loss) from continuing
operations before income tax...... (60,846) 554 8,186 (52,106)
Income tax expense (benefit):....... -- -- -- --
----------- ----------- ------------ ----------
Loss from continuing operation. $(60,846) $554 $8,186 $(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 continuing operations per
common share - basic and diluted: $ (2.03) $ (1.46)
</Table>
See notes to unaudited pro forma financial statements.
37
<Page>
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2002
<Table>
<Caption>
HISTORICAL
ABRAXAS
PETROLEUM FINANCIAL
CORPORATION RESTRUCTURING PRO FORMA
------------ ------------- ---------
Assets:
Cash............................... $ 557 -- $ 557
Accounts receivable................ 6,029 -- 6,029
Other.............................. 1,337 -- 1,337
Assets held for sale............... 74,247 (74,247)(1) --
----------- ----------- ----------
Total current assets........ 82,170 (74,247) 7,923
Net property and equipment.......... 95,926 95,926
Deferred financing fees............. 2,970 2,465 (5) 5,435
Other assets........................ 359 359
----------- ----------- ----------
Total assets................ $ 181,425 $ (71,782) $ 109,643
----------- ----------- ----------
Liabilities and Stockholders' Equity
(Deficit):
Current Liabilities:
Accounts payable.................. $ 5,808 -- 5,808
Current maturities of First Lien
Notes............................. 63,500 (63,500)(2) --
Other current liabilities......... 6,162 (5,000)(2) 1,162
Liabilities related to assets held
for sale......................... 56,697 (56,697)(1) --
----------- ---------- -----------
Total current liabilities.... 132,167 (125,197) 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) --
----------- ----------- -----------
Total....................... 190,979 (15,681) 175,298
Deferred income taxes................ -- -- --
Other liabilities.................... 533 -- 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) 60,739 (7) (208,882)
Accumulated other comprehensive
income............................ (8,703) 4,577 (1) (4,126)
Treasury stock..................... (964) -- (964)
------------ ----------- -----------
Total stockholders' equity
(deficit)................. (142,254) 69,096 (73,158)
------------ ----------- -----------
Total liabilities and
stockholders' equity
(deficit)................. $ 181,425 $ (71,782) $ 109,643
=========== =========== ==========
</Table>
See notes to unaudited pro forma financial statements.
38
<Page>
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Notes to the Unaudited Pro Forma Condensed Consolidated Statements
of Operations:
(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,
classified as discontinued operations as of December 31, 2002, as
follows:
<Table>
Assets: $
Cash 4,325
Accounts receivable 4,940
Net property 53,675
Other 11,307
--------------
$ 74,247
==============
Liabilities:
Accounts payable and accrued liabilities 7,279
Long-term debt 45,964
Other 3,454
--------------
56,697
--------------
</Table>
Additionally, the adjustment to the Accumulated Other Comprehensive
Income represents the estimated portion of the foreign currency
translation adjustments which will be allocated to the divested
operations.
(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
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).
39
<Page>
SELECTED HISTORICAL FINANCIAL DATA
The following historical selected consolidated financial data from
continuing operations are derived from our Consolidated Financial Statements and
the notes thereto included elsewhere in this prospectus. 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.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1998 1999 2000 2001 2002
--------- --------- --------- -------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
CONSOLIDATED STATEMENTS OF
OPERATIONS DATA:
Operating revenue:
Oil and gas production revenues...... $33,705 $21,331 $ 32,165 $ 34,934 $ 21,601
Rig and other revenue................ 2,562 3,255 721 841 706
--------- --------- --------- -------- ---------
Total operating revenue...... 36,267 24,586 32,886 35,775 22,307
--------- --------- --------- --------- ---------
Operating costs and expenses:
Lease operating and production taxes... 10,298 6,627 7,755 9,302 7,910
Depreciation, depletion and
amortization expense.............. 17,633 9,930 12,328 12,336 9,654
General and administrative expense..... 4,434 3,634 4,840 4,937 5,082
General and administrative (Stock-based
compensation)..................... -- -- 2,767 (2,767)
Other.................................. 521 624 717 702 567
Proved property impairment............. 61,224 -- -- -- 32,850
--------- --------- --------- --------- ---------
Total operating expenses..... 94,110 20,815 28,407 24,510 56,063
--------- --------- --------- --------- ---------
Operating income (loss)................ (57,843) 3,771 4,479 11,265 (33,756)
Net interest expense................... 20,039 26,445 22,317 23,844 24,597
Amortization of deferred financing
Fees............................... 1,140 1,484 1,660 1,907 1,325
(Gain) loss on sale of equity
investment............................ -- -- (33,983) 845 --
Other (income) expense................. -- -- 1,016 207 1,168
------- ------- --------- --------- ---------
Income (loss) from continuing
operations before taxes and
extraordinary items................. (79,022) (24,158) 13,369 (15,538) (60,846)
Income tax expense..................... -- 4,158 3,433 505 --
--------- --------- --------- ---------- -------
Income (loss) from continuing
operations ............................ $(79,022) $(28,316) $9,936 $(16,043) $(60,846)
--------- --------- --------- ---------- -------
Income (loss) from continuing
operations per common share:
Basic.............................. $ (12.48) $ (3.56) $ 0.43 $ (0.62) $ (2.03)
Diluted............................ (12.48) (3.56) 0.31 (0.62) (2.03)
CONSOLIDATED BALANCE SHEET DATA:
Total assets........................... $291,498 $322,284 $335,560 $303,616 $181,425
Long-term debt - excluding current
maturities............................. 299,698 273,421 266,441 262,240 190,979
Stockholder's equity (deficit)......... (63,522) (9,505) (6,503) (28,585) (142,254)
</Table>
40
<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. The discussion reflects the sale of our Canadian subsidiaries, Canadian
Abraxas and Old Grey Wolf, and the completion of our financial restructuring in
January 2003. The results of operations of Canadian Abraxas and Old Grey Wolf
are included in "discontinued operations" in our Consolidated Financial
Statements.
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. Crude
oil and natural gas prices increased substantially in 2000. During 2001, crude
oil and natural gas prices weakened substantially from the 2000 levels. During
2002, prices began to increase. 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 the new senior
credit agreement and the 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--Continuing Operations" 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:
o the sales prices of crude oil, natural gas liquids
and natural gas;
o the level of total sales volumes of crude oil,
natural gas liquids and natural gas;
o the ability to raise capital resources and provide
liquidity to meet cash flow needs;
o the level of and interest rates on borrowings; and
o the level and success of exploration and development
activity.
COMMODITY PRICES. Our results of operations are significantly affected
by fluctuations in commodity prices. Price volatility in the natural gas market
has remained prevalent in the last few years. In the first quarter of 2002, we
experienced a decline in energy commodity prices from the prices that we
received in the first quarter of 2001. During the first quarter of 2001, we had
certain crude oil and natural gas hedges in place that prevented us from
realizing the full impact of a favorable price environment. In January 2001, the
market price of natural gas was at its highest level in our operating history
and the price of crude oil was also at a high level. However, over the course of
2001 and the beginning of the first quarter of 2002, prices again became
depressed, primarily due to the economic downturn. Beginning in March 2002,
commodity prices began to increase and continued higher through December 2002.
Prices have continued to increase during the first part of 2003. As of April 7,
2003, the NYMEX price for natural gas was $5.13 per Mcf and $27.96 per Bbl for
crude oil.
41
<Page>
The table below illustrates how natural gas prices fluctuated over the
course of 2001 and 2002. The table below contains the last three day average of
NYMEX traded contracts price and the prices we realized during each quarter for
2001 and 2002 for continuing operations, including the impact of our hedging
activities.
<Table>
<Caption>
Natural Gas Prices by Quarter
(in $ per Mcf)
-------------------------------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31,
2001 2001 2001 2001 2002 2002 2002 2002
------------ ---------- ----------- ------------ ------------ ----------- ----------- -----------
Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 $ 2.38 $ 3.36 $ 3.28 $ 3.99
Realized 4.66 3.38 2.38 2.07 2.27 2.60 2.35 3.46
</Table>
The NYMEX natural gas price on April 7, 2003 was $5.13 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 from continuing operations during each quarter for 2001 and
2002.
<Table>
<Caption>
Crude Oil Prices by Quarter
(in $ per Bbl)
------------------------------------------------------------------------------------------------
Quarter Ended
------------------------------------------------------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31,
2001 2001 2001 2001 2002 2002 2002 2002
----------- ---------- ----------- ------------ ------------ ---------- ----------- ------------
Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48 $ 26.40 $ 27.50 $ 28.29
Realized 28.04 26.23 25.88 19.20 16.30 23.49 27.32 30.91
</Table>
The NYMEX crude oil price on April 7, 2003 was $ 27.96 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. In 2000, 2001 and 2002, we experienced hedging losses of $20.2
million, $12.1 million and $3.2 million, respectively, of which $14.0 million,
$6.6 million and $1.5 million, respectively, were attributable to continuing
operations. 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 $35.5 million, of which
$13.4 million was attributable to discontinued operations.
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. 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 hedge
agreement for the calendar months of March 2003 through February 2004, related
to an additional 5,000 MMBtu, or approximately 25% of our production, which
provides for a floor price of $4.50 per MMBtu.
42
<Page>
SELECTED OPERATING DATA. The following table sets forth certain of our
operating data for our continuing operations for the periods presented.
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT DATA)
2002 2001 2000
------------------ ------------------ ------------------
Operating revenue from continuing operations:*
Crude oil sales*............................ $ 6,461 $ 9,141 $ 5,701
NGLs sales ................................. 142 801 2,710
Natural gas sales*.......................... 14,998 24,992 23,754
Rig and other............................... 706 841 721
------------------ ------------------ ------------------
Total operating revenues ................... $ 22,307 $ 35,775 $ 32,886
================== ================== ==================
Operating income (loss) from continuing
operations................................ $ (33,756) $ 11,265 $ 4,479
Crude oil production (MBbls)................ 264.5 364.6 406.8
NGLs production (MBbls)..................... 9.5 51.3 132.0
Natural gas production (MMcf)............... 5,679.6 7,823.1 8,363.6
Average crude oil sales price (per Bbl)* $ 24.42 $ 25.07 $ 14.01
Average NGLs sales price (per Bbl) $ 14.88 $ 15.61 $ 20.53
Average natural gas sales price (per Mcf)* $ 2.64 $ 3.19 $ 2.84
</Table>
- ----------------
*Revenue and average sales prices are net of hedging activities.
COMPARISON OF YEAR ENDED DECEMBER 31, 2002 TO YEAR ENDED DECEMBER 31, 2001
CONTINUING OPERATIONS
OPERATING REVENUE. During the year ended December 31, 2002, operating
revenue from crude oil, natural gas and natural gas liquids sales decreased by
$13.3 million from $34.9 million in 2001 to $21.6 million in 2002. This decrease
was primarily attributable to a decrease in production volumes. Crude oil and
natural gas revenue was impacted $3.2 million from a decline in commodity prices
and $10.1 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 51.3 MBbls in 2001 to 9.5
MBbls in 2002. Crude oil sales volumes declined from 364.6 MBbls in 2001 to
264.5 MBbls during 2002. Natural gas sales volumes decreased from 7.8 Bcf in
2001 to 5.7 Bcf in 2002. Production declines were primarily attributable to our
disposition of assets during 2002 and natural field declines. During 2002, we
sold producing properties which had contributed 14.0 MBbls of crude oil, and
259.5 MMcf of natural gas during 2002 prior to their disposition. These
properties contributed 43.2 Mbbls of crude oil and natural gas liquids and 815.5
MMcf of natural for the year ended December 31, 2001. In 2001, we drilled a
total of 6.0 gross wells (5.3 net wells) relating to our continuing operations.
Total production from these wells during 2002 contributed a total of 9.8 MBbls
of crude oil and 485.2 MMcf of natural gas. During 2001, we sold producing
properties which had contributed 49.8 MBbls of crude oil, 22.3 MBbls of NGLs and
661.5 MMcf of natural gas during 2001 through the date of disposition. In 2000
we drilled a total of 17 gross wells (16 net wells) relating to our continuing
operations. Total production from these wells during 2001 contributed a total of
63.2 MBbls of crude oil, 6.5 MBbls of NGLs and 890.5 MMcfs of natural gas.
Average sales prices in 2002 net of hedging losses were:
o $ 24.42 per Bbl of crude oil,
43
<Page>
o $ 14.88 per Bbl of natural gas liquids, and
o $ 2.64 per Mcf of natural gas.
Average sales prices in 2001 net of hedging losses were:
o $25.07 per Bbl of crude oil,
o $15.61 per Bbl of natural gas liquids, and
o $ 3.19 per Mcf of natural gas.
LEASE OPERATING EXPENSE. Lease operating expense ("LOE") decreased from
$9.3 million in 2001 to $7.9 million in 2002. LOE on a per Mcfe basis for 2002
was $1.08 per Mcfe as compared to $0.90 per Mcfe in 2001. The increase in the
per Mcfe cost is due to a decline in production volumes. The increase in LOE
from continuing operations is due to additional operations personnel and
increased natural gas lifting cost.
G&A EXPENSE. General and administrative ("G&A") expense increased
slightly from $4.9 million in 2001 to $5.1 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 $0.48 in 2001 to $0.69 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 $2.7 million from $12.3 million in 2001 to $9.6 million in 2002.
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.
Our DD&A expense on a per Mcfe basis for 2002 was $1.32 per Mcfe as compared to
$1.20 per Mcfe in 2001.
INTEREST EXPENSE. Interest expense increased slightly from $23.9
million to $24.7 million for 2002 compared to 2001. The increase was the result
of additional sales pursuant to our production payment arrangement with Mirant
Americas. 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 ($38.9 million
on the U.S. properties and $32.4 million on the discontinued operations 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 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.
44
<Page>
Subsequent to June 30, 2002, commodity prices increased in Canada and we
utilized these increased prices in calculating the ceiling limitation
write-down. The write-down for our discontinued Canadian operations was $83.1
million and $32.9 million relating to continuing operations at June 30, 2002.
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.
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 $505,000
for the year ended December 31, 2001 to zero for the year ended December 31,
2002. The decrease was primarily due to the tax benefit relating to the retained
Canadian properties.
DISCONTINUED OPERATIONS
Loss from discontinued operations increased to $57.7 million in 2002
from a loss of $3.7 million for the year ended 2001. The primary reason for the
increased loss was an impairment charge of $83.1 million in 2002 related to
discontinued Canadian operations. The impairment charge was offset by a deferred
tax benefit of $29.7 million. Discontinued operations also experienced increased
interest expense and general and administrative expense in 2002 as compared to
2001. Interest expense relating to discontinued operations increased to $9.5
million in 2002 compared to $7.6 million in 2001. The increase in interest
expense was due to higher debt levels in 2002 related to the Old Grey Wolf
credit facility with Mirant Canada.
COMPARISON OF YEAR ENDED DECEMBER 31, 2001 TO YEAR ENDED DECEMBER 31, 2000
CONTINUING OPERATIONS
OPERATING REVENUE. During the year ended December 31, 2001, operating
revenue from crude oil, natural gas and natural gas liquids sales applicable to
continuing operations increased by $2.8 million from $32.1 million in 2000 to
$34.9 million in 2001. This increase was primarily attributable to an increase
in commodity prices offset by a decline in production volumes. Increased prices
contributed $7.1 million in additional revenue, which was offset by $4.3 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 132.0 MBbls in 2000 to 51.3
MBbls in 2001. Crude oil sales volumes declined from 406.8 MBbls in 2000 to
364.6 MBbls during 2001. Natural gas sales volumes decreased from 8.4 Bcf in
2000 to 7.8 Bcf in 2001. Production declines were primarily attributable to our
property dispositions and natural field declines. During 2001, we sold
properties that had contributed 49.8 MBbls of crude oil, 22.3 MBbls of NGLs and
661.5 MMcf of natural gas during 2001 through the date of disposition. These
properties contributed 24.4 Mbbls of crude oil and natural gas liquids and 425.3
MMcf of natural gas during the year ended December 2000.
Average sales prices in 2001 net of hedging losses were:
o $ 25.07 per Bbl of crude oil,
o $ 15.61 per Bbl of natural gas liquids, and
o $ 3.19 per Mcf of natural gas.
45
<Page>
Average sales prices in 2000 net of hedging losses were:
o $14.01 per Bbl of crude oil,
o $20.53 per Bbl of natural gas liquids, and
o $ 2.84 per Mcf of natural gas.
LEASE OPERATING EXPENSE. Lease operating expense increased from $7.8
million in 2000 to $9.3 million in 2001. LOE on a per Mcfe basis for 2001 was
$0.90 per Mcfe as compared to $0.67 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 increased from $4.8
million in 2000 to $4.9 million in 2001. Our G&A expense on a per Mcfe basis
increased from $0.42 in 2000 to $0.48 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
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 was
constant at $12.3 million in 2001 and 2000. Our DD&A expense on a per Mcfe basis
for 2001 was $1.20 per Mcfe as compared to $1.06 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 $1.1 million from $22.8
million to $23.9 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 $38.9 million on U.S. 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 $3.4 million for the
year ended December 31, 2000 to $505,000 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.
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DISCONTINUED OPERATIONS
Our loss from discontinued operations increased slightly in 2001
compared to 2000. Loss from discontinued operations for the year ended December
31, 2001 was $3.7 million compared to a loss of $3.3 million in 2000. Higher
incomes taxes in 2001 contributed to this larger loss.
LIQUIDITY AND CAPITAL RESOURCES--CONTINUING OPERATIONS
GENERAL. The crude oil and natural gas industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including
drilling and completion costs of wells;
o acquisition of interests in crude oil and natural gas
properties; and
o production and transportation facilities.
The amount of capital available to us will affect our ability to service our
existing debt obligations and to continue to grow the business through the
development of existing properties and the acquisition of new properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, funding under the new revolving credit facility 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 December 31, 2002 our current liabilities of
approximately $132.2 million exceeded our current assets of $82.2 million.
However, as a result of the financial restructuring completed in January 2003
our current liabilities were reduced by $125.2 million to $7.0 million as of
January 23, 2003, which includes trade payables of $4.1 million and $1.6 million
of revenues due third parties. After giving effect to the scheduled principal
reductions required during 2003, we will have cash interest expense of
approximately $4.0 million. This cash interest relates to the new senior credit
agreement. We do not expect to make cash interest payments with respect to the
outstanding notes, and the issuance of additional notes in lieu of cash interest
payments thereon will not affect our working capital balance.
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<Page>
CAPITAL EXPENDITURES. Capital expenditures in 2000, 2001 and 2002 were
$39.8 million, $19.1 million and $15.9 million, respectively. The table below
sets forth the components of these capital expenditures for continuing
operations for the three years ended December 31, 2000, 2001 and 2002.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2002 2001 2000
---- ---- ----
(DOLLARS IN THOUSANDS)
Expenditure category:
Development $ 15,770 $ 18,867 $ 39,631
Facilities and other 126 259 136
------------------ ------------------- -------------------
Total $ 15,896 $ 19,126 $ 39,767
================== =================== ===================
</Table>
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 the
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
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 for continuing operations are
summarized in the following table and discussed in further detail below:
<Table>
<Caption>
2002 2001 2000
---- ---- ----
(DOLLARS IN THOUSANDS)
Net cash provided by operating activities $ 1,721 $ 11,810 $ 1,050
Net cash provided by (used in) investing activities (6,171) (12,128) 257
Net cash provided by (used in) financing activities (9,692) 2,390 (3,634)
-------------- ------------- ------------
Total $ (14,142) $ 2,072 $ (2,327)
============== ============= ============
</Table>
Operating activities for the year ended December 31, 2002, from
continuing operations provided us $1.7 million of cash. Investing activities
related to continuing operations used $6.2 million during 2002. Our investing
activities included the sale of properties which provided $9.7 million, and the
use of $15.6 million primarily for the development of producing properties.
Financing activities used $9.7 million during 2002, relating primarily to the
repurchase of a production payment.
Operating activities for the year ended December 31, 2001, from
continuing operations, provided us $11.8 million of cash. Investing activities
used $12.1 million during 2001 primarily for the development of producing
properties. Financing activities provided $2.4 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 revolving credit facility, and (iv) sales of producing
properties. Certain covenants under the indenture for the outstanding 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
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<Page>
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:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of
all or substantially all of our assets.
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.
CONTRACTUAL OBLIGATIONS
We are committed to making cash payments in the future on the following
types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of March
31, 2003.
<Table>
<Caption>
Payments due by period:
- ------------------------------- ------------------------------------------------------------------------
Contractual Obligations Less than 1 More than 5
(dollars in thousands) Total year 1-3 years 3-5 years years
- ------------------------------- -------------- ------------- ------------- -------------- --------------
Long-Term Debt (1) $230,638 -- 46,394 (2) 184,244 (3) --
Operating Leases (4) $885 $236 649 -- --
</Table>
- ----------------
(1) Includes the amounts outstanding under the term loan facility, the
revolving credit facility and the outstanding notes.
(2) Represents repayment of the term loan facility and the revolving credit
facility and assumes that interest will be capitalized under the term
loan facility and that periodic interest on the senior credit facility
will be paid on a monthly basis and that we will not draw down
additional funds thereunder.
(3) Assumes that new notes will be issued in lieu of cash interest payments
on the outstanding notes, through the date of maturity.
(4) Office lease obligations. Leases for office space for Abraxas and New
Grey Wolf expire in April 2006 and April 2003, 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.
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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, 2003, our long-term indebtedness consists of the senior
credit facility and the notes issued in connection with the financial
restructuring. The following table sets forth our long-term indebtedness as
of December 31, 2002, and pro forma information reflecting the consummation
of the restructuring transactions.
LONG-TERM INDEBTEDNESS
<Table>
<Caption>
PRO FORMA
DECEMBER 31 DECEMBER 31, 2002
--------------------------- AFTER
2001 2002 RESTRUCTURING(1)
------------ ------------- -----------------
(In thousands)
12 7/8% Senior Secured Notes due 2003 (first lien notes).... $ 63,500 $ 63,500 $ -
11 1/2% Senior Secured Notes due 2004 (second lien notes)... 190,178 190,178 -
11 1/2% Senior Notes due 2004 (old notes)................... 801 801 -
Production Payment ........................................ 8,176 - -
11 1/2% Secured Notes due 2007 (new notes).................. - - 128,600
New Senior Credit Agreement................................. - - 46,700
------------ ------------- -----------------
262,655 254,479 175,300
Less current maturities .................................... 415 63,500 -
------------ ------------- -----------------
$ 262,240 $ 190,979 $ 175,300
============ ============= =================
</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
Exchange Notes" beginning on page 82 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. Portions of accrued interest under the revolving credit facility may
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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 new senior
credit agreement also requires us to enter into hedging agreements on not less
than 25% or more than 75% of our projected oil and gas production. We are also
required to establish deposit accounts at financial institutions acceptable to
the lenders and we are required to direct our customers to make all payments
into these accounts. The amounts in these accounts will be transferred to the
lenders upon the occurrence and during the continuance of an event of default
under the new senior credit agreement.
In addition to the foregoing and other customary covenants, the new
senior credit agreement contains a number of covenants that, among other things,
restrict our ability to:
o incur additional indebtedness;
o create or permit to be created any liens on any of
our properties;
o enter into any change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations
of third parties;
o enter into any forward sales contracts;
o make any payments in connection with distributions,
dividends or redemptions relating to our outstanding
securities, or
o make investments or incur liabilities.
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. Obligations under the new senior 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.
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 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. 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 hedge agreement related to an additional
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5,000 MMBtu, or approximately 25% of our production, 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
At December 31, 2002 we had, subject to the limitation discussed below,
$167.1 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 7. 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, related to continuing operations.
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 equity earnings 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
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production levels we attained during the year ended December 31, 2002 from
continuing operations, 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 $2.2 million for the year.
HEDGING SENSITIVITY
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" 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 Stockholder's 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 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, of which $14.0 million, $6.6
million and $1.5 million respectively were applicable to continuing operations.
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. 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. 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. As of March 31, 2003, the fair market value of our hedge positions is
not material. 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 our hedging 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 $ 368,500
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.
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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 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 loss of $5.7 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 $284,000.
We do not maintain any derivative instruments to mitigate the exposure to
translation risk. However, this does not preclude the adoption of specific
hedging strategies in the future.
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 with respect to
our continuing operations. 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
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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 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 $32.9
million, related to our continuing proved reserves. 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:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o 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
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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 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.
We have applied these standards to the purchase of the minority interest of Old
Grey Wolf.
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 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.
In August 2001, the FASB issued SFAS No. 144, ACCOUNTING FOR THE
IMPAIRMENT OR DISPOSAL OF LONG-LIVED ASSETS, which requires a single accounting
model to be used for long-lived assets to be sold and broadens the presentation
of discontinued operations to include a "component of an entity" (rather than a
segment of a business). A component of an entity comprises operations and cash
flows that can be clearly distinguished, operationally and
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for financial reporting purposes, from the rest of the entity. A component of
an entity that is classified as held for sale, or has been disposed of, is
presented as a discontinued operation if the operations and cash flows of the
component will be (or have been) eliminated from the ongoing operations of
the entity and the entity will not have any significant continuing
involvement in the operations of the component. We adopted SFAS 144,
consequently, the operating results of the Canadian business segment
operations, which were held for sale at December 31, 2002 (and sold after
year end) are included in discontinued operations. .
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 with earlier adoption
encouraged. All other provisions of this standard have been effective for the us
as of May 15, 2002 and did not have a significant impact on our 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 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. We are currently
evaluating the impact the standard will have on our 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. 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
exploration, exploitation, development and production of crude oil and natural
gas. Since January 1, 1991, our principal means of growth has been through the
acquisition and subsequent development and exploitation of producing properties
and related assets. As a result of our historical acquisition activities, we
believe we have a substantial inventory of low risk opportunities, the
exploitation and development of which are critical to the maintenance and growth
of our current production levels. We seek to complement our exploitation and
development activities by selectively participating in exploration projects with
experienced industry partners.
Our principal areas of operation are Texas, western Canada and Wyoming.
At December 31, 2002, we owned interests in 459,880 gross acres (370,589 net
acres) relating to our continuing operations and operated properties accounting
for 87% 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 of our continuing operations were 112.5 Bcfe
with an aggregate PV-10 of $136.6 million.
BUSINESS STRATEGY
Our primary business objectives are to increase reserves, production
and cash flow through the following:
o 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.
o 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, 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 (including $9.4 million included in discontinued
operations), to approximately $4 million, assuming that, as required under the
new senior credit agreement, Abraxas issues additional notes in lieu of cash
interest payments on our outstanding notes. After giving effect to the financial
restructuring on January 23, 2003, the principal amount of our outstanding
indebtedness as of March 31, 2003 is approximately $156.4 million ($109.7
million in outstanding notes and $45.1 million related to the new senior credit
agreement). Due to the accounting treatment under generally accepted accounting
principles for financial restructurings, the reported carrying value of such
total indebtedness will be approximately $175 million ($128.6 million 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
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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
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007, Series A, with a
principal amount equal to $610; and
o 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
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 purchase price was allocated to the
shares of capital stock of Canadian Abraxas and Old Grey Wolf as follows:
<Table>
<Caption>
Number of Shares Purchase Price
---------------- --------------
Canadian Abraxas 5,751 common shares $ 68 million
Old Grey Wolf 12,804,628 common shares $ 70 million
TOTAL PURCHASE PRICE: $138 million
------------
</Table>
After purchase price adjustments and related costs and expenses of
approximately $5.9 million were made, the purchase 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 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 acquisition 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?% Senior Secured Notes, Series A, or
first lien notes, with approximately $66.4 million of the
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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, 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--Continuing Operations--Long-Term Indebtedness" beginning on
page 50.
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 USES OF FUNDS
---------------- -------------
(US DOLLARS IN MILLIONS)
Sale of Canadian Abraxas and
Old Grey Wolf (1)................ $132.1 Redemption of First Lien Notes (3)..... $ 66.4
New Senior Credit Agreement (2).. 46.7 Exchange Offer Cash Payments (4)....... 59.0
Repayment of Old Grey Wolf
Credit Facility (5).................... 46.3
Fees and Expenses...................... 7.1
------
Total Sources.................... $178.8 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.
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.
DRILLING RESULTS
We have successfully completed two new 100% working interest wells in
the Peace River Arch area of Canada which were not included in the sale of
Canadian Abraxas and Old Grey Wolf. In the Ladyfern area of
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Northeastern British Columbia, we are participating for an approximate 17%
working interest in two wells actively drilling. Two additional Ladyfern wells,
with approximately 17% and 50% working interest ownership, are expected to
commence during this winters drilling season.
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 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.
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 41% of our crude oil and natural gas sales. 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 information regarding our hedging
activities.
PRIMARY OPERATING AREAS--CONTINUING OPERATIONS
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
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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 are planned
for 2003. 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 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 to
jointly develop these areas in the future. 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 31, 2002, New Grey Wolf had estimated net proved reserves,
applicable to continuing operations, of 14,904 Mmcfe (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,
applicable to continuing operations, produced an average of approximately 27.5
net Bbls of crude oil and NGLs per day and 570 net Mcf of natural gas per day.
During 2002, we drilled a total of 7 new wells (3.0 net) related to continuing
operations in Canada with a 71% 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 applicable to continuing
operations 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) 10,495 5,432 352,218 277,539
Texas 24,775 19,911 10,881 10,029
Wyoming 3,200 3,200 58,311 54,478
----------- ----------- ----------- -----------
Total 38,470 28,543 421,410 342,046
=========== =========== =========== ===========
</Table>
- ---------------
(1) Represents acreage applicable to continuing operations.
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PRODUCTIVE WELLS
The following table sets forth our total gross and net productive wells
applicable to continuing operations, expressed separately for crude oil and
natural gas, as of December 31, 2002:
<Table>
<Caption>
Productive Wells (1)
--------------------------------------------------
As of December 31, 2002
--------------------------------------------------
State/Country Crude Oil Natural Gas
------------------ ------------------------ ------------------------
Gross Net Gross Net
----------- ----------- ----------- -----------
Canada (1) 15.0 1.3 7.0 1.4
Texas 139.0 111.3 62.0 45.2
Wyoming 5.0 5.0 - -
----------- ----------- ----------- -----------
Total 159.0 117.6 69.0 46.6
=========== =========== =========== ===========
</Table>
- ------------
(1) Represents wells applicable to continuing operations.
RESERVES INFORMATION
The crude oil and natural gas reserves of our continuing operations
have been estimated as of January 1, 2003, January 1, 2002, and January 1, 2001,
by DeGolyer and MacNaughton, of Dallas, Texas. The reserves attributable to New
Grey Wolf as of January 1, 2003 have been estimated by DeGolyer and MacNaughton.
The reserves of Old Grey Wolf as of January 1, 2002 and January 1, 2001 have
been estimated by McDaniel and Associates Consultants Ltd. of Calgary, Alberta.
All Canadian Abraxas and Old Grey Wolf reserves are reflected as discontinued
operations. 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 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 therefrom. 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,
2003, January 1, 2002 and January 1, 2001 related to continuing operations:
<Table>
<Caption>
ESTIMATED PROVED RESERVES (1)
--------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
----------- ----------- -----------
Continuing Operations:
As of January 1, 2001
Crude oil (MBbls) 2,986 1,407 4,393
NGLs (MBbls) 1,322 366 1,688
Natural gas (MMcf) 48,177 66,731 114,908
As of January 1, 2002
Crude oil (MBbls) 1,841 1,170 3,011
NGLs (MBbls) 1,051 352 1,403
Natural gas (MMcf) 40,514 75,154 115,668
As of January 1, 2003
Crude oil (MBbls) 1,714 1,317 3,031
NGLs (MBbls) 144 284 428
Natural gas (MMcf) 43,308 48,458 91,766
</Table>
- ------------------
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(1) Reserves on a Mcf equivalent at December 31, 2002 were 112,520 Mmcfe.
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.
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 - continuing operations. 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. 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 write-down for our discontinued Canadian operations was $83.1
million at June 30, 2002 and 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 $50.4 million in the aggregate,
which are necessary to develop and realize the value of proved undeveloped
reserves on our properties. Any significant
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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 adjusted for the impact of discontinued operations:
<Table>
<Caption>
2002 2001 2000
----------- ----------- -----------
Crude oil production (Bbls) 264,531 364,638 406,829
Natural gas production (Mcf) 5,679,639 7,823,098 8,363,611
Natural gas liquids production
(Bbls) 9,530 51,304 132,005
Mmcfe 7,324 10,318 11,597
Average sales price per Bbl of
crude oil $ 24.42 $ 25.07 $ 14.01
Average sales price per MCF of
natural gas (1) $ 2.64 $ 3.19 $ 2.84
Average sales price per Bbl of
natural gas liquids $ 14.88 $ 15.61 $ 20.53
Average sales price per Mcfe (1) $ 2.95 $ 3.39 $ 2.77
Average cost of production per
Mcfe produced (2) $ 1.08 $ 0.90 $ 0.67
</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, adjusted for the impact of discontinued operations:
<Table>
<Caption>
2002 2001 2000
------------------------ ------------------------ ------------------------
Gross Net(1) Gross Net(1) Gross Net(1)
----------- ----------- ----------- ----------- ----------- -----------
Exploratory
Productive
Crude oil 1.0 1.0 - - - -
Natural gas 3.0 .5 - - - -
Dry holes 3.0 1.5 - - 1.0 1.0
----------- ----------- ----------- ----------- ----------- -----------
Total 7.0 3.0 - - 1.0 1.0
=========== =========== =========== =========== =========== ===========
Development
Productive
Crude oil - - 1.0 1.0 9.0 9.0
Natural gas 3.0 1.1 5.0 4.3 6.0 5.0
Dry holes - - - - 1.0 1.0
----------- ----------- ----------- ----------- ----------- -----------
3.0 1.1 6.0 5.3 16.0 15.0
=========== =========== =========== =========== =========== ===========
</Table>
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<Page>
- ------------------
(1) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is
equivalent to 1.0 net well).
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 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
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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 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.
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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).
(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
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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, 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 metres
exemption is available to production from a well that has not produced for a
12-month period
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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.
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 metre and 35% for prices
above CDN $210 per cubic metre. 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
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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 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
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effect on the environment. Environmental legislation can affect the 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 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.
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As of March 31, 2003, New Grey Wolf in Canada 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 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, Canadian Abraxas' United States agent appointed
for that purpose. Canadian Abraxas has been advised by its Canadian counsel,
Osler, Hoskin & Harcourt, LLP, that there is doubt as to the
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enforceability in Canada against Canadian Abraxas 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................................. 41 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
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.
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.
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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.
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 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 OPTIONS
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($) (#)
---- --------- --------
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 78.
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
VALUE AT ASSUMED
NUMBER OF ANNUAL RATES OF STOCK
SECURITIES EXERCISE PRICE APPRECIATION
UNDERLYING % OF TOTAL PRICE PER FOR
OPTIONS OPTIONS SHARE OPTION TERM
GRANTED GRANTED TO (PRICE AT EXPIRATION -----------
NAME (1) EMPLOYEES GRANT) DATE 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 $0.66 per share of
one-half of all options to purchase Abraxas common stock held by Mr. Watson
(320,282 options), and a reduction in the exercise price of all of stock options
previously issued to other Abraxas employees (approximately 1.8 million
options).
OPTION EXERCISES IN FISCAL YEAR
<Table>
<Caption>
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED
SHARES VALUE OPTIONS ON DECEMBER 31, OPTIONS ON DECEMBER 31,
ACQUIRED BY REALIZED 2002(#) 2002 ($)
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
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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 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.
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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, owns a twin-engine airplane. The airplane
is 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.
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.
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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.
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DESCRIPTION OF THE EXCHANGE NOTES
You can find definitions of certain terms used in this description
under the subheading "Certain Definitions." In this description, the word
"Issuer" or "Abraxas" refers to Abraxas Petroleum Corporation and not to any of
its subsidiaries.
Abraxas issued the outstanding notes and will issue the exchange notes
pursuant to an indenture by and among Abraxas, the Subsidiary Guarantors and
U.S. Bank, N.A., the trustee. The indenture is governed by certain provisions
contained in the Trust Indenture Act of 1939, as amended. The terms of the
outstanding notes and the exchange 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. Abraxas issued
$109,523,000 total principal amount of outstanding notes on January 23, 2003,
which we call the Issue Date, and Abraxas anticipates issuing an additional
$ 3,733,051 of such notes on May 1, 2003 as payment of interest in kind on
the outstanding notes. The indenture also provides for issuance of the exchange
notes in exchange for a like principal amount of outstanding notes issued on
January 23, 2003 in connection with the private exchange offer and any notes
issued thereafter in lieu of cash interest payments in connection with such
notes. The following description is a summary of the material provisions of the
notes, the indenture and the documents providing for the security interests of
the holders of the new secured notes, all of which are filed as exhibits to the
registration statement of which this prospectus is a part. It does not restate
those agreements in their entirety.
The following description is a summary of the material provisions of
the new secured notes, the indenture and the documents providing for the
security interests of the holders of the new secured notes, all of which are
filed as exhibits to the registration statement of which this prospectus is a
part. It does not restate those agreements in their entirety.
BRIEF DESCRIPTION OF THE NOTES AND THE GUARANTEES
THE NOTES
The notes:
o 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;
o provide for interest not paid in cash to be paid in the form
of additional notes;
o are general obligations of the Issuer;
o 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;
o are subordinate to Indebtedness of Issuer under the Senior
Credit Agreement and 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;
o rank senior to all of the Issuer's current and future
Subordinated Indebtedness, if any; and
o 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:
o Sandia;
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o Wamsutter;
o Sandia Operating;
o Eastside Coal;
o Western Associated; and
o New Grey Wolf.
The Guarantees of the notes are:
o general obligations of each current and future Subsidiary
Guarantor;
o senior in right of payment to all existing and future
Subordinated Indebtedness, if any, of each Subsidiary
Guarantor;
o 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;
o 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
o 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.
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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.
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.
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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 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.
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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 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:
o 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.
o 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.
o 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
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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 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.
o 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.
o 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.
o 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.
o 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 Collateral
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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.
o The intercreditor and subordination agreement will remain
applicable if the Issuer or any of its Subsidiaries is subject
to a bankruptcy or insolvency proceeding.
o 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.
o 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.
o 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 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.
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"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.
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
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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:
o 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;
o 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;
o 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
o make any Investment (other than a Permitted Investment).
However, the Issuer may take the following actions:
o 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
o 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.
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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:
o 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
o 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:
o pay dividends or make any other distributions on or in respect
of its Capital Stock;
o make loans or advances, or to pay any Indebtedness or other
obligation owed, to the Issuer or any other Subsidiary;
o guarantee any Indebtedness or any other obligation of the
Issuer or any Subsidiary; or
o 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;
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(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;
o consolidate or merge with or into any Person,
o 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:
o 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
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(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;
o 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;
o 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
o 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 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:
o 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);
o such entity assumes by execution of a supplemental indenture
all of the obligations of the Subsidiary Guarantor under its
Guarantee;
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o immediately after giving effect to such transaction, no
Default or Event of Default shall have occurred and be
continuing; and
o 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:
o 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
o 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.
The foregoing shall not apply to:
o 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;
o 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
o 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:
o 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;
o 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
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future assets using applicable security documents
substantially in the same form as those executed and delivered
on January 23, 2003; and
o 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:
o to the Issuer or a Wholly Owned Subsidiary; or
o 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.
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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, 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
o $2.5 million,
o Restricted Cash as of such Cash Sweep Payment Date,
o 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,
o cash of the Issuer as of such Cash Sweep Payment Date
otherwise applied or required to be applied to Pay Down Debt,
and
o 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:
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o 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:
o 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
o 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,
o 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:
o 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:
o 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 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
o 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.
o In no event shall the Capital Expenditures of the Issuer and its
Subsidiaries for calendar year 2003 exceed the 2003 CapEx Amount.
o 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:
o 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
o 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
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Amount for the two succeeding quarters shall be increased in
the aggregate by an amount equal to the applicable CapEx
Deficit Amount.
o 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:
o 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;
o 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.
o 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
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:
o 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;
o cash interest requirements;
o Capital Expenditures not prohibited by the terms of the indenture;
o 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;
o 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;
o 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;
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o payment of judgments rendered by a court of law;
o assessments issued by any governmental entity;
o 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;
o 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
o 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:
o 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,
o at least 50% of the proceeds of such issuance must immediately be
used to Pay Down Debt, and
o no cash dividends can be paid on such equity unless:
o at least 75% of such proceeds are used to Pay Down Debt,
o the cash dividend payable to the holders of such equity does
not exceed the Cash Coupon on the notes, and
o 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"):
o 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,
o at least 50% of the proceeds of such issuance must immediately be
used to Pay Down Debt, and
o no cash interest can be paid on such Subordinated Indebtedness
unless:
o at least 75% of such proceeds are used to Pay Down Debt,
o the cash portion of any interest payable to the holders of
such Subordinated Indebtedness does not exceed the Cash
Coupon on the notes, and
o the holders of the notes receive in cash (in full) current
interest payments due and payable.
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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.
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:
o 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;
o 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.;
o 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
o 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:
o 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;
o 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;
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o 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
o 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.
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":
o the failure to pay interest on any notes when the same becomes due
and payable;
o 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);
o 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);
o 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
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(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;
o 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;
o certain events of bankruptcy; or
o 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 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:
o the rescission would not conflict with any judgment or decree;
o 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;
o 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;
o the Issuer has paid the Trustee its reasonable compensation and
reimbursed the Trustee for its expenses, disbursements and
advances; and
o 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
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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
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:
o 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
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(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;
o 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 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
o 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:
o 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;
o 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;
o 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;
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o alter, repair, replace, change the location or position of and add
to its structures, machinery, systems, equipment, fixtures and
appurtenances;
o demolish, dismantle, tear down or scrap any obsolete Collateral or
abandon any portion thereof; and
o 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 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:
o no Event of Default has occurred and is continuing as of the date
of the proposed release;
o 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
o all conditions precedent in the indenture relating to the release
in question have been complied with; and
o 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,
o 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;
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o 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
o 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:
o 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;
o 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;
o the rights, powers, trust, duties and immunities of the Trustee;
and
o 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:
o 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:
o 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;
o 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;
o 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;
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o 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;
o 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;
o 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
o 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:
o 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;
o the Issuer has paid all other sums payable under the indenture by
the Issuer; and
o 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:
o reduce the amount of notes whose holders must consent to an
amendment;
o 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;
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o 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;
o make any notes payable in a currency other than that stated in the
notes;
o 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
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;
o 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;
o 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
o 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.
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"2003 CAPEX ANNUAL BUDGET" equals the 2003 Closing CapEx Ratio
multiplied by Total Assets at December 31, 2003.
"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:
o 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.
o The acquisition, to and including the date of the transaction, of
any business or assets, including Permitted Industry Investments.
o 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.
"ASSET ACQUISITION" means:
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(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;
(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
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(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;
(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:
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(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.
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:
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(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,
(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,
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(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.
"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
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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,
(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,
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(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
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 ,
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(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.
"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
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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:
o 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,
o 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 theIntercreditor Agreement,
o 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
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
o 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;
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(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;
(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
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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;
(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;
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(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;
(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,
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(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
(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.
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"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 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
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(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.
"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).
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"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):
o 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,"
o 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,"
o 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";
o expenditures with respect to any non-cash compensation to
officers and employees of the Issuer and its Subsidiaries;
o amounts expended by the Issuer and its Subsidiaries on
selling, general and administrative expenses for Canadian
Abraxas and Old Grey Wolf; and
o 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.
"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
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(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.
"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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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
SCOPE AND LIMITATIONS
The following general discussion summarizes certain United States
federal income tax aspects of the Series A/B Exchange Offer of the outstanding
notes for the exchange notes both of which are referred to collectively, as the
notes. 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
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 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 covered
by this summary 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, 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, should consult their own tax advisors.
As used herein, the term "U.S. Holder" means a holder of notes 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 AND NON-U.S. HOLDER 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, AS
WELL AS ANY TAX CONSEQUENCES THAT MAY ARISE UNDER THE LAWS OF ANY OTHER RELEVANT
FOREIGN, STATE, LOCAL OR OTHER TAXING JURISDICTION.
TAX CONSEQUENCES TO U.S. HOLDERS
TAX CONSEQUENCES OF THE SERIES A/B EXCHANGE OFFER. In general, the
Series A/B Exchange Offer will not constitute an exchange for U.S. federal
income tax purposes because the outstanding notes do not differ materially in
kind or extent from the exchange notes. Instead, the exchange notes will be
treated as a continuation of the outstanding notes.
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As a result, (1) the beneficial owner would not recognize taxable gain
or loss as a result of the Series A/B Exchange Offer, (2) the holding period of
the exchange notes will include the holding period of the outstanding notes
exchanged for the exchange notes, and (3) the adjusted tax basis of the exchange
notes will be the same as the adjusted tax basis, immediately before the Series
A/B Exchange Offer, of the outstanding notes exchanged for the exchange notes.
EACH EXCHANGING HOLDER SHOULD CONSULT WITH HIS OR HER INDIVIDUAL TAX ADVISOR
CONCERNING ANY FOREIGN, STATE OR LOCAL TAX CONSEQUENCES OF THE SERIES A/B
EXCHANGE OFFER AS WELL AS TO THE EFFECT OF HIS OR HER PARTICULAR FACTS AND
CIRCUMSTANCES ON THE MATTERS DISCUSSED HEREIN.
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 (i) the "adjusted issue price" of the notes at the
beginning of each accrual period, multiplied by (ii) 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,
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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.
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 original 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 original
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
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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.
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 U.S. HOLDER.
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 the holding or
receipt of the exchange notes, pursuant to the Series A/B Exchange Offer,
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):
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(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:
- 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 Series A/B exchange, or
the sale or exchange of the notes, 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, 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:
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(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:
- 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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BOOK-ENTRY; DELIVERY AND FORM
Holders of certificated outstanding notes participating in the Series
A/B Exchange Offer will be issued exchange notes in fully registered and
certificated form, to be delivered to each tendering noteholder and registered
in the name of such noteholder in accordance with such noteholder's written
instructions in the letter of transmittal. Principal and cash interest payments
made on certificated exchange notes and any additional notes issued in lieu of
cash interest payments will be made by Abraxas or through a paying agent
directly to the registered holders of such notes. Under the terms of the
indenture for the notes, Abraxas and the trustee will treat the persons in whose
names the notes and any additional notes issued in lieu of cash interest
payments are registered as the owners of such notes for the purpose of receiving
payments of principal and interest and any additional notes issued in lieu of
cash interest on such notes and for all other purposes whatsoever.
The exchange notes issued to tendering noteholders who held their
outstanding notes in book-entry form through DTC will be issued only in the form
of a global certificate deposited with, or on behalf of, the depositary, and
registered in the name of Cede & Co., as the depositary's nominee.
Except as set forth below, the global certificate may be transferred,
in whole and not in part, only by the depositary to its nominee to such
depositary or another nominee of the depositary or by the depositary or its
nominee to a successor of the depositary or a nominee of such successor.
Abraxas understands that the depositary is a limited-purpose trust
company which was created to hold securities for its participating
organizations, or participants, and to facilitate the clearance and settlement
of transactions in such securities between participants through electronic
book-entry changes in accounts of its Participants. Participants include
securities brokers and dealers, banks, trust companies, clearing corporations
and certain other organizations. Access to the depository's book-entry system is
also available to others, such as banks, brokers, dealers and trust companies
that clear through or maintain a custodial relationship with a participant,
either directly or indirectly ("indirect participants"). Persons who are not
participants may beneficially own securities held by the depositary through
participants or indirect participants.
Pursuant to procedures established by the depositary (1) upon deposit
of the global certificate, the depositary will credit the accounts of
participants with portions of the principal amount of the global certificate and
(2) ownership of the exchange notes will be shown on, and the transfer of
ownership thereof will be effected only through, records maintained by the
depositary (with respect to the interest on the depository's participants), the
depository's participants and the depository's indirect participants.
The laws of some jurisdictions require that certain persons take
physical delivery in definitive form of securities that they own. Consequently,
the ability to transfer interests in the global certificate will be limited to
such extent.
So long as the nominee of the depositary is the registered owner of the
global certificate, such nominee will be considered the sole owner or holder of
the exchange notes for all purposes under the indenture. Except as provided
below, the owners of interests in the global certificate will not be entitled to
have exchange notes registered in their names, will not receive or be entitled
to receive physical delivery of exchange notes in definitive form and will not
be considered the owners or holders thereof under the indenture. As a result,
the ability of a person having a beneficial interest in exchange notes
represented by the global certificate to pledge such interest to persons or
entities that do not participate in the depository's system or to otherwise take
actions in respect to such interest may be affected by the lack of a physical
certificate evidencing such interest.
Neither Abraxas, the trustee nor any paying agent will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of interests in the global certificate or for
maintaining, supervising or reviewing any records relating to such interests.
Principal and interest payments on the global certificate registered in
the name of the depository's nominee will be made by Abraxas or through a paying
agent to the depository's nominee as the registered owner of the global
certificate. Under the terms of the indenture, Abraxas and the trustee will
treat the persons in whose names the exchange notes are registered as the owners
of such exchange notes for the purpose of receiving payments of principal and
interest on such exchange notes and for all other purposes whatsoever.
Therefore, neither Abraxas, the
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trustee nor any paying agent has any direct responsibility or liability for
the payment of principal or interest on the exchange notes to owners of
interests in the global certificate. The depositary has advised Abraxas and
the trustee that its present practice is, upon receipt of any payment of
principal or interest, to credit immediately the account of the participants
with payments in amounts proportionate to their respective holdings in
principal amount of interests in the global certificate as shown on the
records of the depositary. Payments by participants and indirect participants
to owners of interests in the global certificate will be governed by standing
instructions and customary practices, as is now the case with securities held
for the accounts of customers in bearer form or registered in "street name,"
and will be the responsibility of such participants or indirect participants.
If the depositary is at any time unwilling or unable to continue as
depositary and a successor depositary is not appointed by Abraxas within 90
calendar days, Abraxas will issue exchange notes in certificated form in
exchange for the global certificate. In addition, Abraxas may at any time
determine not to have the exchange notes represented by a global certificate,
and, in such event, will issue exchange notes in certificated form in exchange
for the global certificate. In either instance, an owner of an interest in the
global certificate would be entitled to physical delivery of such exchange notes
in certificated form. Exchange notes so issued in certificated form will be
issued in denominations of $1,000 and integral multiples thereof and will be
issued in registered form only.
Neither Abraxas nor the trustee shall be liable for any delay by the
depositary or its nominee in identifying the beneficial owners or the related
exchange notes, and each such person may conclusively rely on, and shall be
protected in relying on, instructions from the depositary or its nominee for all
purposes (including with respect to the registration and delivery, and the
respective principal amounts, of the exchange notes to be issued).
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WHERE YOU CAN FIND MORE INFORMATION
Abraxas and the guarantors of the notes have filed the registration
statement regarding the exchange notes 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.
LEGAL MATTERS
Certain legal matters related to the exchange notes offered hereby are
being 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 appearing herein (which report
expresses an unqualified opinion and includes an explanatory paragraph referring
to significant subsequent events), 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.
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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.
TERMS USED TO DESCRIBE COSTS
"DD&A" means depletion, depreciation and amortization.
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"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 continuing operations before income taxes,
interest expense, DD&A and other non-cash charges.
"NGL" means natural gas liquid.
"NYMEX" means the New York Mercantile Exchange.
139
<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 ..........................................F-3
Consolidated Statements of Operations for the years ended December 31, 2000,
2001 and 2002 ...................................................................................F-5
Consolidated Statements of Stockholders' Equity (Deficit) for the years ended
December 31, 2000, 2001 and 2002 ...............................................................F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2000,
2001 and 2002 ...................................................................................F-9
Notes to Consolidated Financial Statements .........................................................F-11
GREY WOLF EXPLORATION INC.
Auditors' Reports for the years ended December 31, 2000, 2001 and 2002 ............................F-44
Comments by Auditors' for US readers on Canada - US reporting differences ..........................F-45
Balance Sheets at December 31, 2002 and 2001 .......................................................F-46
Statements of Earnings and Retained Earnings for the years ended December 31, 2000, 2001
and 2002 ........................................................................................F-47
Statements of Cash Flows for the years ended December 31, 2000, 2001 and 2002.......................F-48
Notes to Financial Statements ......................................................................F-49
</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 3 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.
/s/DELOITTE & TOUCHE LLP
San Antonio, Texas
March 10, 2003
F-2
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<Table>
<Caption>
DECEMBER 31
-------------------------------------
2001 2002
------------------ ------------------
(Dollars in thousands)
Current assets:
Cash ..................................................... $ 3,593 $ 557
Accounts receivable:
Joint owners ......................................... 938 516
Oil and gas production sales ......................... 2,988 5,292
Other ................................................ 135 221
------------------ ------------------
4,061 6,029
Equipment inventory ...................................... 1,061 1,021
Other current assets ..................................... 250 316
------------------ ------------------
8,965 7,923
Assets held for sale ..................................... 163,902 74,247
------------------ ------------------
Total current assets ................................... 172,867 82,170
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................... 290,635 298,972
Unproved, not subject to amortization ................ 4,571 7,052
Other property and equipment ........................... 2,587 2,713
------------------ ------------------
Total ............................................ 297,793 308,737
Less accumulated depreciation, depletion, and
amortization ......................................... 170,307 212,811
------------------ ------------------
Total property and equipment - net ................... 127,486 95,926
Deferred financing fees, net of accumulated amortization
of $7,434 and $8,759 at December 31, 2001 and 2002,
respectively ............................................. 2,779 2,970
Other assets ................................................ 484 359
------------------ ------------------
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>
DECEMBER 31
-------------------------------------
2001 2002
------------------ ------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 3,862 $ 4,171
Joint interest oil and gas production payable ............. 1,180 1,637
Accrued interest .......................................... 5,000 5,000
Other accrued expenses .................................... 1,052 1,162
Hedge liability............................................ 438 -
Current maturities of long-term debt ...................... 415 63,500
------------------ ------------------
11,947 75,470
Liabilities related to assets held for sale................ 57,552 56,697
------------------ ------------------
Total current liabilities................................ 69,499 132,167
Long-term debt ............................................... 262,240 190,979
Future site restoration ..................................... 462 533
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........................... (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>
YEAR ENDED DECEMBER 31
-------------------------------------------------------
2000 2001 2002
-------------------------------------------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 32,165 $ 34,934 $ 21,601
Rig revenues ............................................ 505 756 635
Other ................................................... 216 85 71
------------------ ------------------ -----------------
32,886 35,775 22,307
Operating costs and expenses:
Lease operating and production taxes .................... 7,755 9,302 7,910
Depreciation, depletion, and amortization ............... 12,328 12,336 9,654
Proved property impairment .............................. - - 32,850
Rig operations .......................................... 717 702 567
General and administrative .............................. 4,840 4,937 5,082
General and administrative (Stock-based compensation).... 2,767 (2,767) -
------------------ ------------------ -----------------
28,407 24,510 56,063
------------------ ------------------ -----------------
Operating income (loss) from continuing operations.......... 4,479 11,265 (33,756)
Other (income) expense:
Interest income ......................................... (530) (78) (92)
Amortization of deferred financing fees ................. 1,660 1,907 1,325
Interest expense ........................................ 22,847 23,922 24,689
Financing costs.......................................... - - 967
(Gain) loss on sale of equity investment ................ (33,983) 845 -
Other ................................................... 1,016 207 201
------------------ ------------------ -----------------
(8,890) 26,803 27,090
================== ================== =================
Income (loss) from continuing operations before income tax
and extraordinary item................................... 13,369 (15,538) (60,846)
Income tax expense:
Current ................................................. - 505 -
Deferred ................................................ 3,433 - -
------------------ ------------------ -----------------
Income (loss) from continuing operations before
extraordinary item ...................................... 9,936 (16,043) (60,846)
Loss from discontinued operations .......................... (3,260) (3,675) (57,681)
------------------ ------------------ -----------------
Income (loss) before extraordinary item .................... 6,676 (19,718) (118,527)
Extraordinary item:
Gain on debt extinguishment ............................. 1,773 - -
------------------ ------------------ -----------------
Net income (loss) .......................................... $ 8,449 $ (19,718) $ (118,527)
================== ================== =================
Basic earnings (loss) per common share:
Net income (loss) from continuing operations before
extraordinary item .................................... $ 0.43 $ (0.62) $ (2.03)
Discontinued operations (loss) .......................... (0.14) (0.14) (1.92)
Extraordinary item ...................................... 0.08 - -
------------------ ------------------ -----------------
Net income (loss) per common share - basic ................. $ 0.37 $ (0.76) $ (3.95)
================== ================== =================
</Table>
F-5
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (continued)
<Table>
<Caption>
Diluted earnings (loss) per common share :
Net income (loss) from continuing operations before
extraordinary item .................................... $ 0.31 $ (0.62) $ (2.03)
Discontinued operations (loss) .......................... (0.10) (0.14) (1.92)
Extraordinary item ...................................... 0.05 - -
------------------ ------------------ -----------------
Net income (loss) per common share - diluted .............. $ 0.26 $ (0.76) $ (3.95)
================== ================== =================
</Table>
See accompanying Notes to Consolidated Financial Statements.
F-6
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands except share amounts)
<Table>
<Caption>
ACCUMULATED
COMMON STOCK TREASURY STOCK ADDITIONAL OTHER RECEIVABLES
---------------------------------------- PAID-IN ACCUMULATED COMPREHENSIVE FROM
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT INCOME (LOSS) STOCK SALE TOTAL
----------- ------ ---------- ---------- ---------- ---------- ------------- ------------ ----------
Balance at January 1,
2000..................... 22,747,099 $ 227 152,083 $ (1,071) $ 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 ......... 12,753 - (25,000) 185 80 - - - 265
Purchase of treasury
stock ................ - - 38,800 (78) - - - - (78)
----------- ------ ---------- ---------- ---------- ---------- ------------- ------------ ----------
Balance at December 31,
2000.................... 22,759,852 $ 227 165,883 $ (964) $ 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 ............... 3,386,488 34 - - (34) - - - -
Issuance of common stock
and stock options for
acquisition of
minority interest in
Old Grey Wolf
Exploration, Inc...... 3,990,565 40 - - 9,206 - - - 9,246
Stock options exercised 8,375 - - - 16 - - - 16
----------- ------ ---------- ---------- ---------- ---------- ------------- ------------ ----------
Balance at December 31,
2001....... 30,145,280 $301 165,883 $ (964) $136,830 $(151,094) $(13,561) $ (97) $(28,585)
----------- ------ ---------- ---------- ---------- ---------- ------------- ------------ ----------
</Table>
(continued)
F-7
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)(continued)
(In thousands except share amounts)
<Table>
<Caption>
ACCUMULATED
COMMON STOCK TREASURY STOCK ADDITIONAL OTHER RECEIVABLES
---------------------------------------- PAID-IN ACCUMULATED COMPREHENSIVE FROM
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT INCOME (LOSS) STOCK SALE TOTAL
----------- ------ ---------- ---------- ---------- ----------- ------------- ------------ ----------
Balance at December 31,
2001................ 30,145,280 $ 301 165,883 $ (964) 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.................. 30,145,280 $ 301 165,883 $ (964) $ 136,830 $ (269,621) $ (8,703) $ (97) $(142,254)
=========== ====== ========== ========== ========== =========== ============= ============ ==========
</Table>
See accompanying Notes to Consolidated Financial Statements.
F-8
<Page>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
YEAR ENDED DECEMBER 31
----------------------------------------------
2000 2001 2002
-------------- -------------- --------------
(In thousands)
OPERATING ACTIVITIES
Net income (loss) ........................... $ 8,449 $ (19,718) $ (118,527)
Loss from discontinued operations............ (3,260) (3,675) (57,681)
-------------- -------------- --------------
Income (loss) from continuing operations..... 11,709 (16,043) (60,846)
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Extraordinary gain on
extinguishment of debt................ (1,773) - -
(Gain) loss on sale of equity
investment............................ (33,983) 845 -
Depreciation, depletion, and
amortization ......................... 12,329 12,336 9,654
Proved property impairment ............. - - 32,850
Deferred income tax expense............ 3,433 - -
Amortization of deferred financing
fees.................................. 1,660 1,907 1,325
Stock-based compensation ............... 2,767 (2,767) -
Issuance of common stock and
warrants for compensation ............ 265 - -
Changes in operating assets and
liabilities:
Accounts receivable ................ 8 28,804 18,088
Equipment inventory ................ (538) (76) 201
Other ............................. (184) (281) 496
Accounts payable ................... 5,760 (12,386) (3)
Accrued expenses ................... (403) (529) (44)
-------------- -------------- --------------
Net cash provided by continuing
operations ............................... 1,050 11,810 1,721
Net cash provided by discontinued
operations................................ 20,515 2,119 7,891
-------------- -------------- --------------
Net cash provided by operations.............. 21,565 13,929 9,612
INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ............ (39,767) (19,126) (15,896)
Proceeds from sale of oil and gas
properties................................ 5,542 9,677 9,725
Acquisition of minority interest............. - (2,679) -
Proceeds from sale of equity investment ..... 34,482 - -
-------------- -------------- --------------
Net cash provided by continuing operations... 257 (12,128) (6,171)
Net cash used in discontinued operations..... (19,030) (18,669) 1,135
-------------- -------------- --------------
Net cash used in investing activities........ (18,773) (30,797) (5,036)
</Table>
F-9
<Page>
<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 11,700 -
Payments on long-term borrowings ........... (9,979) (9,326) (8,176)
Deferred financing fees .................... 23 - (1,516)
-------------- -------------- --------------
Net cash (used) provided by continuing
operations .............................. (3,634) 2,390 (9,692)
Net cash (used) provided by discontinued
operations.............................. (184) 18,295 2,267
-------------- -------------- --------------
Net cash (used) provided by financing
activities............................... (3,818) 20,685 (7,425)
-------------- -------------- --------------
Increase (decrease) in cash ................ (1,026) 3,817 (2,849)
-------------- -------------- --------------
Effect of exchange rate changes on cash -
discontinued operations.................. (576) (550) (187)
-------------- -------------- --------------
Increase (decrease) in cash ................ (1,602) 3,267 (3,036)
Cash at beginning of year .................. 1,928 326 3,593
-------------- -------------- --------------
Cash at end of year......................... $ 326 $ 3,593 $ 557
============== ============== ==============
SUPPLEMENTAL DISCLOSURES
Supplemental disclosures of cash flow
information:
Interest paid ......................... $ 22,847 $ 23,922 $ 24,689
============== ============== ==============
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 7.
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 5.
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-10
<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 significant intercompany accounts and
transactions have been eliminated in consolidation.
In January 2003, the Company sold all of the common stock of Canadian
Abraxas Petroleum Limited ("Canadian Abraxas") and Grey Wolf Exploration Inc.
("Old 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"). The Canadian operations had historically been reported
as a geographical business segment. The results of operations, statement of
position and cash flow for all periods presented of Canadian Abraxas and Grey
Wolf, with the exception of the retained properties, is reflected in
discontinued operations in the accompanying financial statements and related
disclosures. See Note 2. Discontinued Operations for further details.
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-11
<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 $451,000, $164,000 and $45,000 of
interest expense related to continuing operations 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 8. 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
F-12
<Page>
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 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
---------------------------------------------
2002 2001 2000
--------------- ------------- -------------
Net income as reported $ (118,527) $ (19,718) $ 8,449
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 (670) (1,284) (1,127)
--------------- ------------- -------------
Pro forma net income (loss) $ (119,197) $ (23,769) $ 10,089
=============== ============= =============
Earnings (loss) per share:
Basic - as reported $ (3.95) $ (0.76) $ 0.37
=============== ============= =============
Basic - pro forma $ (3.98) $ (0.92) $ 0.45
=============== ============= =============
Diluted - as reported $ (3.95) $ (0.76) $ 0.26
=============== ============= =============
Diluted - pro forma $ (3.98) $ (0.92) $ 0.31
=============== ============= =============
</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
F-13
<Page>
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.
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.
The Company has applied these standards to its purchase of the minority interest
in Old Grey Wolf.
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 ASSETS, which requires a single accounting
model to be used for long-lived assets to be sold and broadens the presentation
of discontinued operations to include a "component of an entity" (rather than a
segment of a business). A component of an entity comprises operations and cash
flows that can be clearly distinguished, operationally and for financial
reporting purposes, from the rest of the entity. A component of an entity that
is classified as held for sale, or has been disposed of, is presented as a
discontinued operation if the operations and cash flows of the component will be
(or have been) eliminated from the ongoing operations of the entity and the
entity will not have any significant continuing involvement in the operations of
the component. The Company adopted SFAS 144, consequently, the operating results
of Canadian operations, which were held for sale at December 31, 2002 (and sold
after year end) are included in discontinued operations - see Note 2.
F-14
<Page>
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 with earlier adoption
encouraged. 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 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. DISCONTINUED OPERATIONS
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. The
operations of these subsidiaries, previously reported as a business segment in
prior years, is reported as a discontinued operation for all periods presented
in the accompanying financial statements and the operating results are reflected
separately from the results of continuing operations. Summarized discontinued
operating results and net loss for the years ended December 31, 2000, 2001 and
2002 were:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
2000 2001 2002
----------- ----------- ------------
Total revenue........................................... $ 43,714 $ 41,468 $ 32,013
Loss from operations before income tax (see Note 18).... (1,707) (102) (87,839)
Income tax expense (benefit)............................ 272 1,897 (30,158)
Minority interest in income............................. (1,281) (1,676) -
----------- ----------- ------------
Loss from discontinued operations....................... $ (3,260) $ (3,675) $ (57,681)
=========== =========== ============
</Table>
Assets and liabilities of discontinued operations were as follows:
<Table>
<Caption>
December 31,
----------- -----------
2001 2002
----------- -----------
Assets:
Cash $ 4,012 $ 4,325
Accounts receivable 4,042 4,940
Net property 154,408 53,675
Other 1,440 11,307
----------- -----------
$ 163,902 $ 74,247
=========== ===========
Liabilities:
Accounts payable and accrued liabilities $ 10,391 $ 7,279
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<Page>
Long-tern debt 22,944 45,964
Other 24,217 3,454
----------- -----------
$ 57,552 $ 56,697
=========== ===========
</Table>
Included in the loss from discontinued operations are interest expense
of $8,296, $7,601 and $9,461, and general and administrative expense of
$1,693, $1,508 and $1,698 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 in Note 3 and the amounts related to the
balance of certain notes (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 was
allocated between continuing and discontinued operations by considering the
on-going general and administrative cost associated with the Canadian
properties retained by the Company.
3. RECENT EVENTS
EXCHANGE OFFER. On January 23, 2003, the Company completed an exchange
offer, pursuant to which it offered to exchange cash and securities for all of
the outstanding 11 1/2% Senior Secured Notes due 2004, Series A ("Second Lien
Notes") and 11 1/2% Senior Notes due 2004, Series D, ("Old Notes") issued by
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
such notes tendered in the exchange offer, tendering noteholders received:
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007, Series A, ("New Notes") with
a principal amount equal to $610; and
o 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 - see Note 4. 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.
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 is 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 7/8% 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
F-16
<Page>
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:
o incur additional indebtedness;
o create or permit to be created any liens on any of our
properties;
o enter into any change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations of third
parties;
o enter into any forward sales contracts;
o make any payments in connection with distributions, dividends
or redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
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<Page>
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
purchase price was allocated to the shares of capital stock of Canadian Abraxas
and Old Grey Wolf as follows:
<Table>
<Caption>
Number of Shares Purchase Price
---------------- --------------
Canadian Abraxas 5,751 common shares $68 million
Old Grey Wolf 12,804,628 common shares $70 million
--------------
Total Purchase Price: $138 million
==============
</Table>
After purchase price adjustments and related costs and expenses of
approximately $5.9 million were made, the purchase 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. in the amount of
$46.3 million - see Note 4, 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.
4. LONG-TERM DEBT
As described in Note 3, 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 and is included in,
liabilities related to assets held for sale as of December 31, 2002.
The following is a brief description of the Company's debt for
continuing operations as of December 31, 2002. The pro forma unaudited
information reflects the impact of the financial restructuring transactions -
see Note 3.
Long-term debt consists of the following:
<Table>
<Caption>
PRO FORMA
DECEMBER 31 DECEMBER 31,
--------------------------------- 2002 (a)
2001 2002 (UNAUDITED)
---------------- --------------- --------------
F-18
<Page>
(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 -
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 - -
---------------- --------------- --------------
262,655 254,479 175,300
Less current maturities ........................................... 415 63,500 -
---------------- --------------- --------------
$ 262,240 $ 190,979 $ 175,300
================ =============== ==============
</Table>
- -----------------
(a) After transactions described in Note 3, 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 s 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 3 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.
EXTRAORDINARY ITEM
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.
5. 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 of operations and amortization were not
material to consolidated operations or financial position. As a result of the
sale, the
F-19
<Page>
Company received approximately $34 million, which represented a proportional
interest in the Partnership's proved properties. See Note 11 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 3.
6. 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 ........... - 295,206 306,024
Equipment and other ............................ 7 2,269 2,382
---------------- -----------------
$ 297,793 $ 308,737
================ =================
</Table>
7. STOCKHOLDERS' EQUITY
COMMON STOCK
See Note 3 - 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.
8. STOCK OPTION PLANS AND WARRANTS
F-20
<Page>
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
----------------------------- ----------------------------- -----------------------------
OPTIONS WEIGHTED-AVERAGE OPTIONS WEIGHTED-AVERAGE OPTIONS WEIGHTED-AVERAGE
(000S) EXERCISE PRICE( (000S) EXERCISE PRICE (1) (000S) EXERCISE 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 outstanding remaining exercise Number Weighted average
Exercise price 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-21
<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.
9. 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 $ -
------------- -------------
Total deferred tax liabilities ................... 2,714
Deferred tax assets:
U.S. full cost pool............................. - 2,168
Canadian full cost pool......................... - 1,967
Depletion ...................................... 2,035 2,778
Net operating losses ("NOL")................... 39,393 58,811
Investment in foreign subsidiaries.............. - 32,038
Other .......................................... 956 1,364
------------- -------------
Total deferred tax assets ........................ 42,384 99,126
Valuation allowance for deferred tax assets ...... (39,670) (99,126)
------------- -------------
Net deferred tax assets .......................... 2,714 -
------------- -------------
Net deferred tax liabilities ..................... $ - $ -
============= =============
</Table>
Significant components of the provision (benefit) for income taxes are
as follows:
<Table>
<Caption>
2000 2001 2002
---------- ---------- ----------
Current:
Federal ............................. $ - $ 505 $ -
Foreign ............................. - -
---------- ---------- ----------
$ $ 505 $
========== ========== ==========
Deferred:
F-22
<Page>
Federal ............................. $ 3,433 $ - $ -
Foreign ............................. - -
---------- ---------- ----------
$ 3,433 $ - $ -
========== ========== ==========
</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 3, 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. 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 valuaton 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 5. 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 attributable to continuing operations
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%) .............. $ (4,679) $ 5,438 $ 21,296
(Increase) decrease in deferred tax
asset valuation allowance .......... 1,373 (4,907) (59,456)
NOL utilization - extraordinary gain (603) - -
Higher effective rate of foreign
operations.......................... 69 91 403
Percentage depletion ................. 363 596 683
Investment in foreign subsidiaries .. - - 35,604
F-23
<Page>
Other ................................ 44 (1,723) 1,470
---------- ---------- ----------
$ (3,433) $ (505) $ -
========== ========== ==========
</Table>
10. 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.
11. 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>
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 5) 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.
12. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted
earnings per share:
<Table>
<Caption>
2000 2001 2002
------------- -------------- ---------------
F-24
<Page>
Numerator:
Numerator for basic and diluted earnings
per share - net income (loss) before
extraordinary item and discontinued
operations............................. $ 9,936,000 $ (16,043,000) $ (60,846,000)
Discontinued operations.................. (3,260,000) (3,675,000) (57,681,000)
Extraordinary item....................... 1,773,000 - -
------------- -------------- ---------------
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) before extraordinary
item................................... $ 0.43 $ (0.62) $ (2.03)
Discontinued operations.................. (0.14) (0.14) (1.92)
Extraordinary item....................... 0.08 - -
------------- -------------- ---------------
Net income (loss) per common share...... $ 0.37 $ (0.76) $ (3.95)
============= ============== ===============
Diluted earnings (loss) per share:
Net income (loss) from continuing
operations before extraordinary item... $ 0.31 $ (0.62) $ (2.03)
Discontinued operations.................. (0.10) (0.14) (1.92)
Extraordinary item....................... 0.05 - -
------------- -------------- ---------------
Net income (loss) per common share -
diluted............................... $ 0.26 $ (0.76) $ (3.95)
============= ============== ===============
</Table>
For the year ended December 31, 2002, 2001 and 2000 , 5.9 million
shares, 4.3 million shares and 3.0 million shares respectively, were excluded
from the calculation of diluted earnings per share since their inclusion would
have been anti-dilutive.
13. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Selected results of operations from continuing 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 previously reported .. $ 29,086 $ 21,116 $ 14,901 $ 12,140
Net revenue - discontinued operations.. (15,869) (11,298) (7,124) (7,177)
---------- ---------- ---------- ----------
Net revenue - continuing operations.... 13,217 9,818 7,777 4,963
---------- ---------- ---------- ----------
Operating income (loss) - as previously
reported ............................ 12,112 9,002 2,113 (4,102)
F-25
<Page>
Operating income (loss) - discontinued
operations........................... (7,403) (3,437) 171 2,809
---------- ---------- ---------- ----------
Operating income (loss) - continuing
operation............................ 4,709 5,565 2,284 (1,293)
---------- ---------- ---------- ----------
Net income (loss) ..................... 255 (1,274) (5,849) (12,850)
Net income (loss) per common share-
basic ............................... $ 0.01 $ (0.05) $ (0.22) $ (0.43)
Net income (loss) per common share-
diluted ............................. $ 0.01 $ (0.05) $ (0.22) $ (0.43)
Year Ended December 31, 2002
Net revenue - as previously reported... $ 11,807 $ 14,235 $ 11,061 $ 17,217
Net revenue - discontinued operations.. (7,191) (8,476) (6,049) (10,297)
---------- ---------- ---------- ----------
Net revenue - continuing operations.... 4,616 5,759 5,012 6,920
---------- ---------- ---------- ----------
Operating income (loss) - as
previously reported ................. (735) (115,879) 490 4,760
Operating income (loss) - discontinued
operations........................... 6 (82,597) 1,050 3,933
---------- ---------- ---------- ----------
Operating income (loss) - continuing
operations........................... (741) (33,282) (560) 827
---------- ---------- ---------- ----------
Net income (loss) ..................... $ (8,699) $ (95,690) $ (8,438) $ (5,700)
Net income (loss) per common share-
basic and diluted ................... $ (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, $32.9 million relating to continuing
operations and $83.1 million relating to discontinued operations. During the
fourth quarter of 2001, the Company incurred a ceiling limitation write-down of
$2.6 million relating to discontinued operations, 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.
14. 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.
15. 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.
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
------------- ------------ ------------ -------------- --------------
F-26
<Page>
ASSETS:
Current assets:
Cash..................................... $ 557 $ - $ - $ - $ 557
Accounts receivable, less allowance for
doubtful accounts...................... 4,482 10,539 2,165 (11,157) 6,029
Equipment inventory...................... 860 142 19 - 1,021
Other current assets..................... 316 - - - 316
------------- ------------ ------------ -------------- --------------
6,215 10,681 2,184 (11,157) 7,923
Assets held for sale..................... - 25,515 48,732 - 74,247
------------- ------------ ------------ -------------- --------------
Total current assets................... 6,215 36,196 50,916 (11,157) 82,170
Property and equipment - net................ 74,435 11,144 10,347 - 95,926
Deferred financing fees, net................ 2,970 - - - 2,970
Other assets ............................... 108,558 - - (108,199) 359
------------- ------------ ------------ -------------- --------------
Total assets ............................ $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425
============= ============ ============ ============== ==============
LIABILITIES AND STOCKHOLDER'S DEFICIT:
Current liabilities:
Accounts payable ........................ $ 15,928 $ - $ 894 $ (11,014) $ 5,808
Accrued interest ........................ 5,000 - - - 5,000
Other accrued expenses .................. 1,162 - - - 1,162
Current maturities of long-term debt .... 63,500 - - - 63,500
------------- ------------ ------------ -------------- --------------
85,590 - 894 (11,014) 75,470
Liabilities related to assets held for sale. - 4,427 52,270 - 56,697
------------- ------------ ------------ -------------- --------------
Total current liabilities.............. 85,590 4,427 53,164 (11,014) 132,167
Long-term debt ............................. 138,350 52,629 - - 190,979
Future site restoration ................... - 519 14 - 533
------------- ------------ ------------ -------------- --------------
223,940 57,575 53,178 (11,014) 323,679
Stockholders' equity (deficit).............. (31,762) (10,235) 8,085 (108,342) (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 $ - $ - $ - $ 3,593
Accounts receivable, less allowance for
doubtful accounts...................... 17,184 - 9,905 (23,028) 4,061
Equipment inventory ..................... 1,061 - - - 1,061
Other current assets .................... 250 - - - 250
------------- ------------ ------------ -------------- --------------
22,088 - 9,905 (23,028) 8,965
Assets held for sale........................ - 115,528 48,374 163,902
------------- ------------ ------------ -------------- --------------
Total current assets................... 22,088 115,528 58,279 (23,028) 172,867
Property and equipment - net................ 116,462 10,314 710 - 127,486
Deferred financing fees, net .............. 2,779 - - - 2,779
Other assets ............................... 108,801 784 - (109,101) 484
------------- ------------ ------------ -------------- --------------
F-27
<Page>
------------- ------------ ------------ -------------- --------------
Total assets ............................ $ 250,130 $ 126,626 $ 58,989 $(132,129) $ 303,616
============= ============ ============ ============== ==============
LIABILITIES AND STOCKHOLDER'S DEFICIT:
Current liabilities:
Accounts payable ........................ $ 10,642 $ 16,723 $ 662 $ (22,985) $ 5,042
Accrued interest ........................ 5,000 - - - 5,000
Other accrued expenses .................. 1,052 - - - 1,052
Hedge liability ......................... 438 - - - 438
Current maturities of long-term debt .... 415 - - - 415
------------- ------------ ------------ -------------- --------------
17,547 16,723 662 (22,985) 11,947
Liabilities related to assets held for
sale................................... - 22,170 35,382 - 57,552
------------- ------------ ------------ -------------- --------------
Total current liabilities.............. 17,547 38,893 36,044 (22,985) 69,499
Long-term debt ............................. 209,611 52,629 - - 262,240
Future site restoration ................... - 462 - - 462
------------- ------------ ------------ -------------- --------------
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)
<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 $ - $ 766 $ - $ 21,601
Rig revenues .................................. 635 - - - 635
Other ........................................ 71 - - - 71
-------------- ------------ ------------ -------------- --------------
21,541 - 766 - 22,307
Operating costs and expenses:
Lease operating and production taxes .......... 7,639 - 271 - 7,910
Depreciation, depletion, and amortization ..... 9,194 - 460 - 9,654
Proved property impairment .................... 28,178 3,425 1,247 - 32,850
Rig operations ................................ 567 - - - 567
General and administrative .................... 4,045 - 1,037 - 5,082
-------------- ------------ ------------ -------------- --------------
49,623 3,425 3,015 - 56,063
-------------- ------------ ------------ -------------- --------------
Operating income (loss)........................... (28,082) (3,425) (2,249) - (33,756)
Other (income) expense:
Interest income ............................... (92) - - - (92)
Amortization of deferred financing fees........ 1,325 - - - 1,325
Interest expense............................... 24,689 - - - 24,689
Other ......................................... 1,168 - - - 1,168
-------------- ------------ ------------ -------------- --------------
27,090 - - - 27,090
-------------- ------------ ------------ -------------- --------------
Income (loss) from continuing operations before
income tax .................................... (55,172) (3,425) (2,249) - (60,846)
Income tax expense (benefit)...................... - - - - -
Loss from discontinued operations................. - (44,448) (13,233) - (57,681)
-------------- ------------ ------------ -------------- --------------
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
F-28
<Page>
<Table>
<Caption>
(IN THOUSANDS)
ABRAXAS
PETROLEUM RESTRICTED NON-GUARANTOR RECLASSIFI- ABRAXAS
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS PETROLEUM
INC. - PARENT (CANADIAN (OLD GREY AND CORPORATION AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ------------- ------------- ---------------
Revenues:
Oil and gas production revenues ............... $ 34,934 $ - $ - $ - $ 34,934
Gas processing revenues ....................... - - - - -
Rig revenues .................................. 756 - - - 756
Other ........................................ 85 - - - 85
----------- ---------- ------------- ------------- ---------------
35,775 - - - 35,775
Operating costs and expenses:
Lease operating and production taxes .......... 9,302 - - - 9,302
Depreciation, depletion, and amortization ..... 12,336 - - - 12,336
Rig operations ................................ 702 - - - 702
General and administrative .................... 3,742 - 1,195 - 4,937
General and administrative (Stock-based
Compensation)................................ (2,767) - - - (2,767)
----------- ---------- ------------- ------------- ---------------
23,315 1,195 - 24,510
----------- ---------- ------------- ------------- ---------------
Operating income (loss)........................... 12,460 (1,195) - 11,265
Other (income) expense:
Interest income ............................... (78) - - - (78)
Amortization of deferred financing fees........ 1,907 - - - 1,907
Interest expense............................... 23,922 - - - 23,922
Other ......................................... 1,052 - - - 1,052
26,803 - - - 26,803
----------- ---------- ------------- ------------- ---------------
Income (loss) from continuing operations before -
income tax .................................... (14,343) (1,195) (15,538)
Income tax expense (benefit)...................... 505 - - - 505
Loss from discontinued operations................. - (6,512) 2,837 - (3,675)
----------- ---------- ------------- ------------- ---------------
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
PETROLEUM RESTRICTED NON-GUARANTOR RECLASSIFI- ABRAXAS
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS PETROLEUM
INC. - PARENT (CANADIAN (OLD GREY AND CORPORATION AND
COMPANY(1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ------------- ------------- ---------------
Revenues:
Oil and gas production revenues ............... $ 32,165 $ - $ - $ - $ 32,165
Rig revenues .................................. 505 - - - 505
Other ........................................ 216 - - - 216
----------- ---------- ------------- ------------- ---------------
32,886 - - - 32,886
Operating costs and expenses:
Lease operating and production taxes .......... 7,755 - - - 7,755
Depreciation, depletion, and amortization ..... 12,328 - - - 12,328
Rig operations ................................ 717 - - - 717
F-29
<Page>
General and administrative .................... 4,115 - 725 - 4,840
General and administrative (Stock-based
Compensation)................................ 2,767 - - - 2,767
----------- ---------- ------------- ------------- ---------------
27,682 - 725 - 28,407
----------- ---------- ------------- ------------- ---------------
Operating income (loss)........................... 5,204 (725) - 4,479
Other (income) expense:
Interest income ............................... (530) - - - (530)
Amortization of deferred financing fees........ 1,660 - - - 1,660
Interest expense .............................. 22,847 - - - 22,847
Gain on sale of equity investment ............. (33,983) - - - (33,983)
Other ......................................... 1,116 - - - 1,116
----------- ---------- ------------- ------------- ---------------
(8,890) - - - (8,890)
----------- ---------- ------------- ------------- ---------------
Income (loss) from continuing operations before
income tax and extraordinary item.............. 14,094 (725) - 13,369
Income tax expense (benefit)...................... 3,433 - - 3,433
----------- ---------- ------------- ------------- ---------------
Income (loss) before extraordinary item........... 10,661 (725) - 9,936
Loss from discontinued operations................. - (5,241) 1,981 - (3,260)
Extraordinary item:
Gain on debt extinguishment.................... 1,773 - - - 1,773
----------- ---------- ------------- ------------- ---------------
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)
<Table>
<Caption>
ABRAXAS ABRAXAS
PETROLEUM RESTRICTED NON-GUARANTOR RECLASSIFI- PETROLEUM
CORPORATION SUBSIDIARY SUBSIDIARY CATIONS CORPORATION
INC. PARENT (CANADIAN (OLD GREY AND AND
COMPANY (1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ------------ ------------ -------------
OPERATING ACTIVITIES
Net income (loss) ........................... $ (55,172) $ (47,873) $ (15,482) $ - $ (118,527)
Loss from discontinued operations............ - (44,448) (13,233) - (57,681)
----------- ---------- ------------ ------------- -------------
Loss from continuing operations.............. (55,172) (3,425) (2,249) - (60,846)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization ......................... 9,194 - 460 - 9,654
Proved property impairment ............. 28,178 3,425 1,247 - 32,850
Deferred income tax (benefit) expense... - - - -
Amortization of deferred financing fees. 1,325 - - - 1,325
Changes in operating assets and
liabilities:
Accounts receivable ................ 18,088 - - - 18,088
Equipment inventory ................ 201 - - - 201
Other ............................. 234 - 262 - 496
Accounts payables and accrued
expenses ......................... (47) - - - (47)
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by continuing
operations .............................. 2,001 - (280) - 1,721
Net cash provided by discontinued operations. - 1,430 6,461 - 7,891
----------- ---------- ------------ ------------- -------------
Net cash provided by operations.............. 2,001 1,430 6,181 - 9,612
INVESTING ACTIVITIES
F-30
<Page>
Capital expenditures, including purchases
and development of properties ............ (5,070) - (10,826) - (15,896)
Proceeds from sale of oil and gas
properties................................ 9,725 - - - 9,725
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by continuing
operations................................ 4,655 - (10,826) - (6,171)
Net cash used in discontinued operations..... - 16,856 (15,721) - 1,135
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by investing
activities................................ 4,655 16,856 (26,547) - (5,036)
FINANCING ACTIVITIES
Payments on long-term borrowings ............ (8,176) - - - (8,176)
Deferred financing fees...................... (1,516) - - - (1,516)
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by continuing
operations activities..................... (9,692) - - - (9,692)
Net cash provided by discontinued operations. - (18,262) 20,529 - 2,267
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by financing
activities................................ (9,692) (18,262) 20,529 - (7,425)
----------- ---------- ------------ ------------- -------------
Effect of exchange rate changes on cash ..... - (24) (163) - (187)
----------- ---------- ------------ ------------- -------------
Increase (decrease) in cash ................. (3,036) - - - (3,036)
Cash at beginning of year ................... 3,593 - - - 3,593
----------- ---------- ------------ ------------- -------------
Cash at end of year.......................... 557 - - - $ 557
=========== ========== ============ ============= =============
</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
PETROLEUM RESTRICTED NON-GUARANTOR
CORPORATION SUBSIDIARY SUBSIDIARY RECLASSIFI- ABRAXAS PETROLEUM
INC. - PARENT (CANADIAN (OLD GREY CATION AND CORPORATION AND
COMPANY (1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ------------ ------------- -------------
OPERATING ACTIVITIES
Net income (loss) ........................... $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
Income (loss) from discontinued operations... - (6,512) 2,837 - (3,675)
---------- ---------- ------------ ------------- -------------
Income (loss) from continuing operations..... (14,848) - (1,195) - (16,043)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Loss on sale of equity investment....... 845 - - - 845
Depreciation, depletion, and
amortization ......................... 12,336 - - - 12,336
Amortization of deferred financing fees. 1,907 - - - 1,907
Stock-based compensation ............... (2,767) - - - (2,767)
Changes in operating assets and
liabilities:
Accounts receivable ................ 28,804 - - - 28,804
Equipment inventory ................ (76) - - - (76)
Other ............................. (281) - - - (281)
Accounts payables and accrued
expenses ......................... (12,915) - - - (12,915)
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by continuing (1,195) - 11,810
operations ............................... 13,005
Net cash provided (used) by discontinued
operations................................ - (428) 2,547 - 2,119
----------- ---------- ------------ ------------- -------------
F-31
<Page>
Net cash provided (used) by operating
activities................................ 13,005 (428) 1,352 13,929
INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ............ (19,126) - - - (19,126)
Proceeds from sale of oil and gas
properties................................ 9,677 - - - 9,677
Acquisition of minority interest ............ (2,679) - - - (2,679)
----------- ---------- ------------ ------------- -------------
Net cash provided (used)continuing
operations................................ (12,128) - - - (12,128)
Net cash provided (used) by discontinued
operations................................ - 569 (19,238) - (18,669)
----------- ---------- ------------ ------------- -------------
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 - - - 11,700
Payments on long-term borrowings ............ (9,326) - - - (9,326)
----------- ---------- ------------ ------------- -------------
Net cash provided (used) continuing operations
2,390 - - - 2,390
Net cash provided (used) by discontinued
operations................................ - - 18,295 - 18,295
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by financing 2,390 - 18,295 - 20,685
activities
----------- ---------- ------------ ------------- -------------
3,267 141 409 - 3,817
Effect of exchange rate changes on cash ..... - (141) (409) - (550)
----------- ---------- ------------ ------------- -------------
Increase (decrease) in cash ................. 3,267 - - - 3,267
Cash at beginning of year ................... 326 - - 326
----------- ---------- ------------ ------------- -------------
Cash at end of year.......................... $ 3,593 - - $ - $ 3,593
=========== ========== ============ ============= =============
</Table>
CONDENSED CONSOLIDATING PARENT, RESTRICTED
SUBSIDIARY AND NON-GUARANTOR STATEMENT OF CASH FLOW
FOR THE YEAR ENDED DECEMBER 31, 2000
(IN THOUSANDS)
<Table>
<Caption>
ABRAXAS
PETROLEUM RESTRICTED NON-GUARANTOR
CORPORATION SUBSIDIARY SUBSIDIARY RECLASSIFI- ABRAXAS PETROLEUM
INC. - PARENT (CANADIAN (OLD GREY CATION AND CORPORATION AND
COMPANY (1) ABRAXAS) WOLF) ELIMINATIONS SUBSIDIARIES
----------- ---------- ------------ ------------- -------------
OPERATING ACTIVITIES
Net income (loss) ........................... $ 12,434 $ (5,241) $ 1,256 $ - $ 8,449
Income (loss) from discontinued operations... - (5,241) 1,981 - (3,260)
----------- ---------- ------------ ------------- -------------
Income (loss) from continuing operations..... 12,434 - (725) - 11,709
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Extraordinary 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 - - - 12,329
Deferred income tax expense............. 3,433 - - 3,433
Amortization of deferred financing fees. 1,660 - - - 1,660
Stock-based compensation ............... 2,767 - - - 2,767
Issuance of common stock and warrants
for compensation ..................... 265 - - - 265
F-32
<Page>
Changes in operating assets and
liabilities:
Accounts receivable ................ 8 - - - 8
Equipment inventory ................ (538) - - - (538)
Other ............................. (184) - - - (184)
Accounts payables and accrued
expenses ......................... 5,357 - - - 5,357
----------- ---------- ------------ ------------- -------------
Net cash provided by continuing operations .. 1,775 - (725) - 1,050
Net cash provided by discontinued operations. - 8,655 11,860 - 20,515
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by operations....... 1,775 8,655 11,135 - 21,565
INVESTING ACTIVITIES
Capital expenditures, including purchases
and development of properties ............ (39,767) - - - (39,767)
Proceeds from sale of oil and gas
properties ............................... 5,542 - - - 5,542
Proceeds from sale of equity investment ..... 34,482 - - - 34,482
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by continuing
operations................................ 257 - - - 257
Net cash provided (used) in discontinued
operations................................ - (8,256) (10,774) - (19,030)
----------- ---------- ------------ ------------- -------------
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) - - - (9,979)
Deferred financing fees ..................... 23 - - - 23
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by continuing
operations................................ (3,634) - - - (3,634)
Net cash provided (used) by discontinued
operations................................ - (184) - (184)
----------- ---------- ------------ ------------- -------------
Net cash provided (used) by financing (3,634) - (184) - (3,818)
activities
----------- ---------- ------------ ------------- -------------
(1,602) 399 177 - (1,026)
Effect of exchange rate changes on cash ..... - (399) (177) - (576)
----------- ---------- ------------ ------------- -------------
Increase (decrease) in cash ................. (1,602) - - - (1,602)
Cash at beginning of year ................... 1,928 - - - 1,928
----------- ---------- ------------ ------------- -------------
Cash at end of year.......................... $ 326 $ - $ - $ - $ 326
=========== ========== ============ ============= =============
</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 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-33
<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.
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 is expected to be 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, of which $6.6 million and $1.5 million was from continuing
operations, which is accounted for in Oil and Gas Production Revenue.
Under the terms of the New Senior Secured Credit Agreement, (see Note
3) 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:
<Table>
<Caption>
Accumulated Other
Comprehensive Comprehensive Income
Income (Loss) (Loss)
------------------- ------------------------
For the year
Ended As of
December 31, 2002 December 31,2002
------------------- ------------------------
Accumulated other comprehensive loss at December 31, 2001 ......... $ (13,561)
Net loss........................................................ $ (118,527)
-------------------
F-34
<Page>
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, $32.9 million related to
continuing operations and $83.1 million related to discontinued operations.
F-35
<Page>
19. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The accompanying table presents information concerning the Company's
crude oil and natural gas producing activities from continuing operations as
required by Statement of Financial Accounting Standards No. 69, "Disclosures
about Oil and Gas Producing Activities." Capitalized costs relating to oil and
gas producing activities are as follows:
<Table>
<Caption>
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------------------------------------
2001 2002
------------------------------------------------ ------------------------------------------------
TOTAL U.S. CANADA TOTAL U.S. CANADA
--------------- --------------- -------------- -------------- -------------- ---------------
(In thousands)
Proved crude oil and natural
gas properties ............$ 290,635 $ 284,182 $ 6,453 $ 298,972 $ 279,401 $ 19,571
Unproved properties ......... 4,571 - 4,571 7,052 - 7,052
--------------- --------------- -------------- -------------- -------------- ---------------
Total ..................... 295,206 284,182 11,024 306,024 279,401 26,623
Accumulated depreciation,
depletion, and
amortization, and
impairment ................ (168,124) (168,124) - (210,313) (205,181) (5,132)
--------------- --------------- -------------- -------------- -------------- ---------------
Net capitalized costs ...$ 127,082 $ 116,058 $ 11,024 $ 95,711 $ 74,220 $ 21,491
=============== =============== ============== ============== ============== ===============
</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.
-------------- -------------- -------------- -------------- --------------
(In thousands)
Property acquisition costs:
Proved ....................... $ - $ - $ - $ - $ -
Unproved ..................... - - - - -
-------------- -------------- -------------- -------------- --------------
$ - $ - $ - $ - $ -
============== ============== ============== ============== ==============
Property development and
exploration costs ............ $ 39,631 $ 39,631 $ - $ 18,867 $ 18,867
============== ============== ============== ============== ==============
</Table>
<Table>
<Caption>
YEARS ENDED DECEMBER 31
-----------------------------------------------------------
2002
-------------- --------------------------------------------
CANADA TOTAL U.S. CANADA (1)
-------------- ---------------------------- --------------
Property acquisition costs:
Proved ....................... $ - $ - $ - $ -
Unproved ..................... - - - -
-------------- ---------------------------- --------------
$ - $ - $ - $ -
============== ============================ ==============
Property development and
exploration costs ............ $ - $ 15,770 $ 4,944 $ 10,826
============== ============================ ==============
</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.
-------------- -------------- -------------- -------------- ---------------
(In thousands)
Revenues ................... $ 32,165 $ 32,165 $ - $ 34,934 $ 34,934
Production costs ........... (7,755) (7,755) - (9,302) (9,302)
Depreciation, depletion,
and amortization ......... (11,968) (11,968) - (11,976) (11,976)
Proved property impairment . - - - - -
General and administrative . (1,118) (1,118) - (1,073) (1,073)
Income taxes (expense)
benefit................... - - - - -
-------------- -------------- -------------- -------------- ---------------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) .......... $ 11,324 $ 11,324 $ - $ 12,583 $ 12,583
============== ============== ============== ============== ===============
Depletion rate per barrel
of oil equivalent, before
impact of impairment ..... $ 6.19 $ 6.19 $ - $ 6.96 $ 6.96
============== ============== ============== ============== ===============
</Table>
<Table>
<Caption>
YEARS ENDED DECEMBER 31
-----------------------------------------------------------
2002
------------- ---------------------------------------------
CANADA TOTAL U.S. CANADA
------------- --------------- -------------- --------------
Revenues ................... $ - $ 21,601 $ 20,835 $ 766
Production costs ........... - (7,910) (7,639) (271)
Depreciation, depletion,
and amortization ......... - (9,339) (8,879) (460)
Proved property impairment . - (32,850) (28,178) (4,672)
General and administrative . - (1,270) (1,011) (259)
Income taxes (expense)
benefit................... - - - -
------------- --------------- -------------- --------------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) .......... $ - $(29,768) $ (24,872) $ (4,896)
============= =============== ============== ==============
Depletion rate per barrel
of oil equivalent, before
impact of impairment ..... $ - $ 7.65 $ 7.55 $ 10.30
============== ============== =============== ==============
</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
---------------------------------- ----------------------------------
LIQUID NATURAL LIQUID NATURAL
HYDROCARBONS GAS HYDROCARBONS GAS
------------------- -------------- ------------------- --------------
(BARRELS) (MCF) (BARRELS) (MCF)
(In Thousands)
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
Balance at January 1, 2000 (1) ........... 6,421 80,417 6,421 80,417
Revisions of previous estimates ........ 54 (13,441) 54 (13,441)
Extensions and discoveries ............. 315 57,371 315 57,371
Purchase of minerals in place .......... - - - -
Production ............................. (539) (8,364) (539) (8,364)
Sale of minerals in place .............. (170) (1,075) (170) (1,075)
------------------- -------------- ------------------- --------------
Balance at December 31, 2000.............. 6,081 114,908 6,081 114,908
Revisions of previous estimates ........ (688) 3,318 (688) 3,318
Extensions and discoveries ............. 361 12,086 354 4,886
Production ............................. (416) (7,823) (416) (7,823)
Sale of minerals in place .............. (924) (6,821) (924) (6,821)
------------------- -------------- ------------------- --------------
Balance at December 31, 2001.............. 4,414 115,668 4,407 108,468
Revisions of previous estimates ........ (69) (17,705) (63) (15,248)
Extensions and discoveries ............. 231 9,036 - -
Production ............................. (274) (5,680) (264) (5,472)
Sale of minerals in place .............. (843) (9,553) (843) (9,553)
------------------- -------------- ------------------- --------------
Balance at December 31, 2002.............. 3,459 91,766 3,237 78,195
=================== ============== =================== ==============
</Table>
<Table>
<Caption>
CANADA
--------------------------------------
LIQUID NATURAL
HYDROCARBONS GAS
--------------------- ----------------
(BARRELS) (MCF)
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
Balance at January 1, 2000 (1) ........... - -
Revisions of previous estimates ........ - -
Extensions and discoveries ............. - -
Purchase of minerals in place .......... - -
Production ............................. - -
Sale of minerals in place .............. - -
--------------------- ----------------
Balance at December 31, 2000.............. - -
Revisions of previous estimates ........ - -
Extensions and discoveries ............. 7 7,200
Production ............................. - -
Sale of minerals in place .............. - -
--------------------- ----------------
Balance at December 31, 2001.............. 7 7,200
Revisions of previous estimates ........ (6) (2,457)
Extensions and discoveries ............. 231 9,036
Production ............................. (10) (208)
Sale of minerals in place .............. - -
--------------------- ----------------
Balance at December 31, 2002.............. 222 13,571
===================== ================
</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.
F-38
<Page>
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES (CONTINUED)
<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 RESERVES:
December 31, 2000........ 4,309 48,177 4,309 48,177 - -
=================== ============== =================== ============== ================== =============
December 31, 2001 ....... 2,892 40,514 2,892 40,514 - -
=================== ============== =================== ============== ================== =============
December 31, 2002........ 1,858 43,308 1,753 34,776 105 8,532
=================== ============== =================== ============== ================== =============
</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 reserves from continuing
operations 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.
F-40
<Page>
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 ........ $ 1,274,871 $ 1,274,871 $ - $ 313,640 $ 313,640 $ -
Future production and
development costs ........ (254,667) (254,667) - (138,296) (138,296) -
Future income tax expense .. (65,421) (65,421) - - - -
--------------- -------------- ---------- -------------- ------------- -------------
Future net cash flows ...... 954,783 954,783 - 175,344 175,344 -
Discount ................... (468,663) (468,663) - (98,157) (98,157) -
--------------- -------------- ---------- -------------- ------------- -------------
Standardized Measure of
discounted future net
cash relating to proved
reserves ................. $ 486,120 $ 486,120 $ $ 77,187 $ 77,187 $
=============== ============== ========== ============== ============= =============
YEARS ENDED DECEMBER 31
---------------------------------------------
2002
---------------------------------------------
TOTAL U.S. CANADA
---------------------------------------------
(In thousands)
Future cash inflows ........ $ 454,052 $ 389,061 $ 64,991
Future production and
development costs ........ (177,306) (158,507) (18,799)
Future income tax expense .. - - -
---------------- ------------- ------------
Future net cash flows ...... 276,746 230,554 46,192
Discount ................... (140,162) (120,238) (19,924)
---------------- ------------- ------------
Standardized Measure of
discounted future net
cash relating to proved
reserves ................. $ 136,584 $ 110,316 $ 26,268
================ ============= ============
</Table>
F-41
<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
for continuing operations:
<Table>
<Caption>
YEAR ENDED DECEMBER 31
----------------------------------------------------------
2000 2001 2002
------------------- ------------------- ------------------
(In thousands)
Standardized Measure, beginning
of year ................................. $ 123,283 $ 486,120 $ 77,187
Sales and transfers of oil and gas
produced, net of production costs ....... (24,410) (25,632) (13,691)
Net changes in prices and development
and production costs from prior year .... 356,237 (333,920) 64,652
Extensions, discoveries, and improved
recovery, less related costs ............ 215,895 4,010 31,122
Purchases of minerals in place ............ - - -
Sales of minerals in place ................ (7,631) (36,681) (9,089)
Revision of previous quantity estimates ... (47,794) (2,400) (12,888)
Change in future income tax expense ....... (65,422) 65,422 -
Other ..................................... (76,366) (128,344) (8,428)
Accretion of discount ..................... 12,328 48,612 7,719
------------------- ------------------- ------------------
Standardized Measure, end of year ....... $ 486,120 $ 77,187 $ 136,584
=================== =================== ==================
</Table>
F-42
<Page>
FINANCIAL STATEMENTS
GREY WOLF EXPLORATION INC.
DECEMBER 31, 2002
F-43
<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-44
<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-45
<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-46
<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-47
<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-48
<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-49
<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-50
<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-51
<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-52
<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-53
<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-54
<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-55
<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-56
<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-57
<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-58
<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-59
<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-60
<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-61
<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), Canadian GAAP (47,613) 4,135 3,940
Capitalized interest (a) 168 119 69
Depreciation, depletion and site restoration (e) (2,401) (62) (88)
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, Canadian GAAP (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-62
<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
CANADIAN INCREASE U.S. CANADIAN INCREASE U.S.
GAAP (DECREASE) GAAP GAPP (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-63
<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, Canadian GAAP 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,
Canadian GAAP (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-64
<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-65
<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-66
<Page>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. 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.
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 21. 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).
II-1
<Page>
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 Corporation. (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. (Filed as Exhibit
3.7 to the Abraxas Registration Statement on Form S-1, filed February
7, 2003 (the "2003 Abraxas Registration Statement").
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
(Filed as Exhibit 3.9 to the 2003 Abraxas Registration Statement).
3.10 Articles of Incorporation of Eastside Coal Company, Inc. (Filed as
Exhibit 3.10 to the 2003 Abraxas Registration Statement).
3.11 Certificate of Incorporation of Grey Wolf Exploration Inc. (Filed as
Exhibit 3.11 to the 2003 Abraxas Registration Statement).
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 (Filed as
Exhibit 3.13 to the 2003 Abraxas Registration Statement).
3.14 By-Laws of Sandia Operating Corp. (Filed as Exhibit 3.14 to the 2003
Abraxas Registration Statement).
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 (Filed as Exhibit 3.16
to the 2003 Abraxas Registration Statement).
3.17 By-Laws of Eastside Coal Company, Inc. (Filed as Exhibit 3.17 to the
2003 Abraxas Registration Statement).
3.18 By-Laws of Grey Wolf Exploration Inc. (Filed as Exhibit 3.18 to the
2003 Abraxas Registration Statement).
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).
II-2
<Page>
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 Issuer's 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 Corp., 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 111/2% Secured Note due 2007 (Filed as Exhibit A to the
Indenture).
**4.9 Form of Letter of Transmittal.
**4.10 Form of Notice of Guaranteed Delivery.
*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).
+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).
II-3
<Page>
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 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).
II-4
<Page>
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 ("Foothill"), as the Arranger
and Administrative Agent (the "Loan Agreement"). (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. (Filed as Exhibit 24.1 to
the 2003 Abraxas Registration Statement).
24.2 Power of Attorney of Franklin Burke (Filed as Exhibit 24.2 to the 2003
Abraxas Registration Statement).
24.3 Power of Attorney of Frederick M. Pevow, Jr. (Filed as Exhibit 24.3 to
the 2003 Abraxas Registration Statement).
24.4 Power of Attorney of James C. Phelps (Filed as Exhibit 24.4 to the 2003
Abraxas Registration Statement).
24.5 Power of Attorney of Joseph A. Wagda (Filed as Exhibit 24.5 to the 2003
Abraxas Registration Statement).
II-5
<Page>
25.1 Statement of eligibility of trustee for the Indenture (Filed as Exhibit
25.1 to the 2003 Abraxas Registration Statement).
27.1 Financial Data Schedule (Omitted pursuant to Regulation S-K, Item 601(c)).
* Previously filed.
** Filed herewith.
+ Management Compensatory Plan or Agreement.
II-6
<Page>
ITEM 22. UNDERTAKINGS
A. 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 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.
B. Each of the undersigned registrants hereby undertakes as follows:
that prior to any public reoffering of the securities registered hereunder
through use of a prospectus which is a part of this registration statement, by
any person or party who is deemed to be an underwriter within the meaning of
Rule 145(c), the issuer undertakes that such reoffering prospectus will contain
the information called for by the applicable registration form with respect to
reofferings by persons who may be deemed underwriters, in addition to the
information called for by the other Items of the applicable form. C. Each of the
undersigned registrants undertakes that every prospectus (i) that is filed
pursuant to paragraph B immediately preceding, or (ii) that purports to meet the
requirements of section 10(a)(3) of the Act and is used in connection with an
offering of securities subject to Rule 415, will be filed as a part of an
amendment to the registration statement and will not be used until such
amendment is effective, and that, for purposes 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.
II-7
<Page>
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 April 17, 2003.
ABRAXAS PETROLEUM CORPORATION
By: /s/ ROBERT L. G. WATSON
-----------------------
Chairman of the Board, Chief
Executive Officer and President
II-8
<Page>
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, April 17, 2003
- ---------------------- President, Chief Executive Officer
Robert L.G. Watson (Principal Executive Officer) and Director
of Abraxas
/s/ CHRIS E. WILLIFORD Executive Vice President, April 17, 2003
- ------------------------------------------ Treasurer, and Chief Financial
Chris E. Williford Officer (Principal Financial and
Accounting Officer) of Abraxas
/s/ ROBERT W. CARINGTON Executive Vice President April 17, 2003
- ------------------------------------------ of Abraxas
Robert W. Carington, Jr.
* Director of Abraxas April 17, 2003
- ------------------------------------------
Craig S. Bartlett, Jr.
* Director of Abraxas April 17, 2003
- ------------------------------------------
Franklin A. Burke
Director of Abraxas
- ------------------------------------------
Ralph F. Cox
* Director of Abraxas April 17, 2003
- ------------------------------------------
Frederick M. Pevow, Jr.
* Director of Abraxas April 17, 2003
- ------------------------------------------
James C. Phelps
* Director of Abraxas April 17, 2003
- ------------------------------------------
Joseph A. Wagda
*BY: /S/ CHRIS E. WILLIFORD
Chris E. Williford
Attorney-in-Fact
</Table>
II-9
<Page>
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 April 17, 2003.
SANDIA OIL & GAS CORPORATION
By: /s/ ROBERT L.G. WATSON
-----------------------
President
II-10
<Page>
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 April 17, 2003
- ------------------------------------------ Officer) and Director of
Robert L.G. Watson Sandia Oil & Gas Corporation
/s/ CHRIS E. WILLIFORD Vice President (Principal April 17, 2003
- ------------------------------------------ Financial and Accounting
Chris E. Williford Officer) and Director of Sandia
Oil & Gas Corporation
/s/ ROBERT W. CARINGTON Vice President and Director April 17, 2003
- ------------------------------------------ of Sandia Oil & Gas Corporation
Robert W. Carington, Jr.
</Table>
II-11
<Page>
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 April 17, 2003.
SANDIA OPERATING CORP.
By: /s/ ROBERT L.G. WATSON
-----------------------
President
II-12
<Page>
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 April 17, 2003
- ------------------------------------------ Officer) and Director of
Robert L.G. Watson Sandia Operating Corp.
/s/ CHRIS E. WILLIFORD Vice President (Principal April 17, 2003
- ------------------------------------------ Financial and Accounting
Chris E. Williford Officer) and Director of Sandia
Operating Corp.
/s/ ROBERT W. CARINGTON Vice President and Director April 17, 2003
- ------------------------------------------ of Sandia Operating Corp.
Robert W. Carington, Jr.
</Table>
II-13
<Page>
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 April 17, 2003.
WAMSUTTER HOLDINGS, INC.
By: /s/ ROBERT L.G. WATSON
----------------------
President
II-14
<Page>
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 April 17, 2003
- ------------------------------------------ Officer) and Director of
Robert L.G. Watson Wamsutter
/s/ CHRIS E. WILLIFORD Vice President (Principal April 17, 2003
- ------------------------------------------ Financial and Accounting
Chris E. Williford Officer) and Director of Wamsutter
/s/ ROBERT W. CARINGTON Vice President and Director April 17, 2003
- ------------------------------------------ of Wamsutter
Robert W. Carington, Jr.
</Table>
II-15
<Page>
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 April 17, 2003.
WESTERN ASSOCIATED ENERGY CORPORATION
By: /s/ ROBERT L.G. WATSON
-----------------------
President
II-16
<Page>
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 April 17, 2003
- ------------------------------------------ Officer) and Director of
Robert L.G. Watson Western Associated Energy
Corporation
/s/ CHRIS E. WILLIFORD Vice President (Principal April 17, 2003
- ------------------------------------------ Accounting Officer) and
Chris E. Williford Director of Western Associated
Energy Corporation
/s/ ROBERT W. CARINGTON Vice President and April 17, 2003
- ------------------------------------------ Director of Western
Robert W. Carington, Jr. Associated Energy Corporation
</Table>
II-17
<Page>
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 April 17, 2003.
EASTSIDE COAL COMPANY, INC.
By: /s/ ROBERT L.G. WATSON
----------------------
President
II-18
<Page>
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 April 17, 2003
- ------------------------------------------ Officer) and Director of
Robert L.G. Watson Eastside Coal Company, Inc.
/s/ CHRIS E. WILLIFORD Vice President (Principal April 17, 2003
- ------------------------------------------ Accounting Officer) and
Chris E. Williford Director of Eastside Coal
Company, Inc.
/s/ ROBERT W. CARINGTON Vice President and April 17, 2003
- ------------------------------------------ Director of Eastside Coal
Robert W. Carington, Jr. Company, Inc.
</Table>
II-19
<Page>
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 April 17, 2003.
GREY WOLF EXPLORATION INC.
By: /s/ ROBERT L.G. WATSON
----------------------
President
<Page>
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 April 17, 2003
- ------------------------------------------ Officer) and Director of
Robert L.G. Watson Grey Wolf Exploration Inc.
/S/ CHRIS E. WILLIFORD Vice President (Principal April 17, 2003
- ------------------------------------------ Financial and Accounting
Chris E. Williford Officer) of Grey
Wolf Exploration Inc.
/S/ VINCE TKACHICK Vice President/COO and Director April 17, 2003
- ------------------------------------------ of Grey Wolf Exploration Inc.
Vince Tkachick
</Table>
II-21
<Page>
EXHIBIT INDEX
EXHIBIT NUMBER:
4.9 Form of Letter of Transmittal
4.10 Form of Notice of Guaranteed Delivery
5.2 Opinion of Osler, Hoskin & Harcourt LLP
23.1 Consent of Deloitte & Touche LLP
23.2 Consent of Deloitte & Touche LLP Chartered Accountants
23.3 Consent of DeGolyer and MacNaughton.
23.6 Consent of Osler, Hoskin & Harcourt LLP