ABRAXAS PETROLEUM CORP, 10-K, 1997-03-31

ABRAXAS PETROLEUM CORP
10-K, 1997-03-31
CRUDE PETROLEUM & NATURAL GAS

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)

[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934

For the Fiscal Year Ended December 31, 1996

[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

Commission File Number 0-19118

ABRAXAS PETROLEUM CORPORATION

(Exact name of Registrant as specified in its charter)

Nevada 74-2584033
(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)

500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232

Registrant's telephone number,
including area code (210) 490-4788

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Common Stock, par value $.01 per share

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __

Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]

The aggregate market value of the voting stock (which consists solely of
shares of Common Stock) held by non-affiliates of the registrant as of March 21,
1997, (based upon the average of the $10.50 per share "Bid" and $10.75 per share
"Asked" prices), was approximately $45,911,049 on such date.

The number of shares of the issuer's Common Stock, par value $.01 per
share, outstanding as of March 21, 1997 was 5,732,101 shares of which 4,878,049
shares were held by non-affiliates.

Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 1997 Annual Meeting of Shareholders to be held on May
23, 1997 have been incorporated by reference herein (Part III).

<PAGE>

ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS

PART I
Page

Item 1. Business. ........................................................4
General ......................................................4
Principal Areas of Activity....................................5
Markets and Customers..........................................6
Risk Factors...................................................7
Regulation of Crude Oil and Natural Gas Activities............13
Natural Gas Price Controls....................................14
State Regulation of Crude Oil and Natural Gas Production......15
Environmental Regulation......................................18
Employees.....................................................18
Recent Activities.............................................18

Item 2. Properties.......................................................19
Exploratory and Developmental Acreage.........................19
Productive Wells..............................................19
Reserves Information..........................................20
Crude Oil and Natural Gas Production and Sales Price .........21
Drilling Activities...........................................22
Office Facilities.............................................23
Other Properties..............................................23

Item 3. Legal Proceedings................................................23

Item 4. Submission of Matters to a Vote of
Security Holders............................................23
Item 4a.Executive Officers of the Company.................................23

PART II

Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters.............................24
Market Information............................................24
Holders.......................................................24
Dividends.....................................................24

Item 6. Selected Financial Data..........................................25

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................25
Results of Operations.........................................25
Liquidity and Capital Resources...............................28

<PAGE>

Item 8. Financial Statements and Supplementary Data......................31

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................31

PART III

Item 10. Directors and Executive Officers................................32

Item 11. Executive Compensation..........................................32

Item 12. Security Ownership of Certain Beneficial Owners and Management..33

Item 13. Certain Relationships and Related Transactions..................33

PART IV

Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K....................................33

<PAGE>

PART I

Item 1. Business

General

Abraxas Petroleum Corporation, a Nevada corporation ("Abraxas" or the
"Company") 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, the Permian Basin of western Texas, Canada
and Wyoming. The Company's business strategy is to acquire and develop producing
crude oil and natural gas properties and related assets that contain the
potential for increased value through exploitation and development. The Company
utilizes a disciplined acquisition strategy, focusing its efforts on producing
properties and related assets possessing the following characteristics: a
concentration of operations; significant, quantifiable development potential;
historically low operating expenses; and the potential to reduce general and
administrative expenses per barrel of crude oil equivalent ("BOE"). Since
December 31, 1990, the Company has made 16 acquisitions of crude oil and natural
gas producing properties totaling an estimated 46.0 million barrels of crude oil
equivalent ("MMBOE") of proved reserves at an average acquisition cost of
approximately $3.83 per BOE.

Since January 1996, the Company has had operations in the United
States and Canada and since November 1996, the Company's operations have
consisted of two segments: exploration and production and natural gas gathering
and processing. The revenues and operating earnings for each country and each
industry segment and the identifiable assets attributable to each country and
each industry segment for the year ended December 31, 1996 are set forth in Note
15 to the Notes to Consolidated Financial Statements included elsewhere herein.

At December 31, 1996, the Company operated 364 wells and owned
non-operated interests in 155 net wells. Average net daily production for the
year ended December 31, 1996 was 1,985 barrels ("Bbls") of crude oil and natural
gas liquids and 17,397 thousand cubic feet ("Mcf") of natural gas. The Company's
proved reserves and present value (discounted at 10%) of estimated future net
cash flows (before income taxes) of proved crude oil and natural gas reserves
("Present Value of Proved Reserves") has increased from an estimated 889
thousand barrels of crude oil equivalent ("MBOE") and $11.9 million,
respectively, at January 1, 1991 to an estimated 47.5 MMBOE and $415.9 million,
respectively, at January 1, 1997. Of the Company's proved reserves at January 1,
1997, 86.6% were classified as proved developed reserves and 87.5% of the
Present Value of Proved Reserves at such date was attributable to such proved
developed reserves. The Company also owned varying interests in 13 natural gas
processing plants or compression facilities with capacity of 128.0 MMCF per day
and 197 miles of natural gas gathering systems.

Since January 1, 1991, the Company's principal means of growth has
been through the acquisition and subsequent development and exploitation of
producing properties and related assets. The Company intends to continue its
growth strategy emphasizing reserve additions through its exploitation efforts.
There can be no assurance that attractive acquisition opportunities will arise,
that the Company will be able to consummate acquisitions in the future or that
sufficient external or internal funds will be available to fund the Company's
acquisitions. The Company may also use, where appropriate, it's equity
securities as all or part of the consideration for such acquisitions.

Although the Company intends to devote most of its resources to the
exploitation and development of the producing properties acquired, the Company
intends to selectively participate in the exploration for new reserves of crude
oil and natural gas. The Company intends to develop prospects internally and to
participate with industry partners in prospects generated by other parties in
its exploration activities.

The Company periodically evaluates, and from time to time has elected
to sell, certain of its mature producing properties. Such sales enable the
Company to maintain financial flexibility, reduce overhead and redeploy the
proceeds therefrom to activities that the Company believes to have a potentially
higher financial return. See "Recent Activities".

<PAGE>

Principal Areas Of Activity

Texas Gulf Coast and South Texas

Portilla Field, San Patricio County, Texas The Company acquired a 50%
working interest in the Portilla Field in April 1993 and the remaining 50% in
November 1996. The field, discovered in the 1950's by Superior Oil Company,
produces from numerous Miocene, Frio and Vicksburg age sands from depths between
4,000 feet and 9,000 feet. A report prepared by independent petroleum engineers
showed estimated net proved reserves of 3.3 million barrels ("MMBbls") of crude
oil and natural gas liquids and 5.0 billion cubic feet ("Bcf") of natural gas
from this field, with a Present Value of Proved Reserves of $36.1 million at
January 1, 1997. For the year ended December 31, 1996, the field produced an
average of approximately 611 net Bbls of crude oil and 219 net Bbls of natural
gas liquids per day and sold approximately 1,867 net Mcf of natural gas per day
from 33 active wells. The Company also owns a 100% interest in a natural gas
processing plant with capacity of approximately 20 MMcf per day. The Company is
the operator of the natural gas processing plant and all of the wells in this
field.

East White Point Field, San Patricio County, Texas. The Company
acquired an approximate 30% working interest in this field in April 1993 and an
additional 30% interest in November 1996. The field produces crude oil and
natural gas from numerous sands in the Lower Frio formation from 9,000 feet to
13,000 feet. A report prepared by independent petroleum engineers showed
estimated net proved reserves of 3.2 MMBbls of crude oil and natural gas liquids
and 29.7 Bcf of natural gas from this field with a Present Value of Proved
Reserves of $60.0 million at January 1, 1997. The Company operates 11 wells and
Marathon Oil Company ("Marathon") operates another 10 wells in which the Company
has an interest in this field. For the year ended December 31, 1996, the field
produced an average of approximately 184 net Bbls of crude oil and 250 net Bbls
of natural gas liquids per day and sold 3,266 net Mcf of natural gas per day
from 19 active wells. The Company also owns an approximate 43% interest in a
natural gas processing plant. The Company is the operator of this natural gas
processing plant.

Stedman Island Field, Nueces County, Texas. The Company acquired a
25% working interest in this field in April 1993, an additional 25% in October
1995 and the remaining 50% in November 1996. The field produces crude oil and
natural gas from the Frio sands at depths of 8,500 to 10,000 feet. A report
prepared by independent petroleum engineers showed estimated net proved reserves
of 519.7 MBbls of crude oil and natural gas liquids and 10.1 Bcf of natural gas
from this field with a Present Value of Proved Reserves of $16.5 million at
January 1, 1997. During 1996, the field produced an average of approximately 50
net Bbls of crude oil and natural gas liquids and 966 net Mcf of natural gas per
day.

Permian Basin - West Texas

Delaware Area (Howe, ROC, Block 16, Taurus, Gomez, N.E. Oates and
Nine Mile Draw Fields). In connection with the acquisition of producing
properties located in West Texas from a group of sellers in July 1994 (the "West
Texas Properties"), the Company acquired working interests ranging from 18% to
100% in 35 wells, 29 of which are operated by the Company. The fields produce
from Devonian, Wolfcamp, Ellenburger and Cherry Canyon sands from depths ranging
from 6,500 feet to 17,600 feet. A report prepared by independent petroleum
engineers showed estimated net proved reserves of 4.6 MMBbls of crude oil and
natural gas liquids and 29.9 Bcf of natural gas in these fields, with a Present
Value of Proved Reserves of $91.9 million at January 1, 1997. During 1996 the
Company drilled 22 wells in this area and produced an average of 6,509 net MCF
of natural gas and 650 net Bbls of crude oil and natural gas liquids per day
from these fields.

Sharon Ridge and Westbrook Fields, Scurry and Mitchell Counties,
Texas. The Company drilled its first wells in the Westbrook Field in 1978 and
operated approximately 40 wells prior to 1992. The two fields produce crude oil
from Permian age carbonates between 1,700 feet and 3,500 feet. In 1992, the
Company acquired working interests ranging from 57.5% to 100% and became the
operator of 124 wells in the Sharon Ridge Field, which is adjacent to the
Westbrook Field. A report prepared by independent petroleum engineers showed
estimated net proved reserves of 1.4 MMBbls of crude oil and natural gas liquids
from this field, with a Present Value of Proved Reserves of $8.4 million at
January 1, 1997. For the year ended December 31, 1996, the Company produced an
average of approximately 171 net Bbls of crude oil per day from these fields.
The Company is currently investigating waterflooding and development drilling to
enhance production.

<PAGE>

Canada

In January 1996, the Company invested $3.0 million in Grey Wolf
Exploration Ltd., ("Grey Wolf"), a privately held Canadian corporation, which,
in turn, invested in newly-issued shares of Cascade Oil and Gas Ltd.,
("Cascade"), an Alberta-based corporation whose shares are traded on the Alberta
Stock Exchange. The Company owns 78% of the outstanding capital stock of Grey
Wolf and, through Grey Wolf, the Company owns 52% of the outstanding capital
stock of Cascade. Cascade owns 4.3 net producing crude oil and natural gas wells
and 12,000 net acres of undeveloped leases in southwestern Saskatchewan. A
report prepared by independent petroleum engineers showed estimated net proved
reserves of 120 MBbls of crude oil, with a Present Value of Proved Reserves of
$1.3 million (CDN) approximately $950,000 (U.S.), at January 1, 1997.

In November 1996, the Company's wholly owned subsidiary, Canadian
Abraxas Petroleum Limited ("Canadian Abraxas") acquired 100% of the outstanding
capital stock of CGGS Canadian Gas Gathering Systems Inc. ("CGGS"). Canadian
Abraxas owns producing properties in western Canada consisting primarily of
natural gas reserves and interests ranging from 10% to 100% in 197 miles of
natural gas gathering systems and 11 natural gas processing plants or
compression facilities (the "Canadian Abraxas Plants"), four of which are
operated by Canadian Abraxas. The Canadian Abraxas Properties consist of 154,968
gross acres (86,327 net acres) and 120 gross wells (68.8 net wells), 48 of which
are operated by Canadian Abraxas. As of January 1, 1997, the Canadian Abraxas
Properties had total proved reserves of 10,382 MBOE (88.5% natural gas) with
Present Value of Proved Reserves of $85.4 million, 88.6% of which was
attributable to proved developed reserves. The Canadian Abraxas Plants had
aggregate net natural gas processing capacity of 98.3 MMcf per day at December
31, 1996. For the twelve months ended December 31, 1996, the Canadian Abraxas
Plants processed an average of 182.8 gross MMcf (65.7 net MMcf) of natural gas
per day, of which 19.6% (9.7% net) was custom processed for third parties.

Wyoming

On September 30, 1996, the Company acquired producing properties in
the Wamsutter area of southwestern Wyoming (the "Wyoming Properties"). The
Wyoming Properties consist of 19,587 gross acres (14,091 net acres) and 25 gross
wells (20.4 net wells), 22 of which are operated by the Company. In addition,
the Company acquired various overriding royalty interests in four wells. As of
January 1, 1997, the Wyoming properties had proven reserves of 10,570 MBOE
(69.2% natural gas) with Present Value of Proved Reserves of $108.2 million,
89.5% of which was attributable to proved developed reserves.

Markets and Customers

The revenues generated by the Company's operations are 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 received by the
Company for its crude oil and natural gas production and the level of such
production are subject to wide fluctuations and depend on numerous factors
beyond the Company's control including seasonality, the condition of the United
States and the Canadian economies (particularly the manufacturing sector),
foreign imports, political conditions in other 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 the Company's proved reserves and the
Company's revenues, profitability and cash flow.

In order to manage its exposure to price risks in the marketing of
its crude oil and natural gas, the Company from time to time has 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, the Company 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 its futures position and sell
its production to a customer. Such contracts may expose the Company to the risk
of financial loss in certain circumstances, including instances where production
is less than expected, the Company's 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. Such contracts may also
restrict the ability of the Company to benefit from unexpected increases in
crude oil and natural gas prices.

<PAGE>

In connection with the reacquisition of the Portilla and Happy Fields
in November 1996, the Company assumed certain commodity swaps on variable
volumes of oil and gas. The agreements settle monthly with amounts either due to
or from Christiania Bank, New York Branch ("Christiania") based on the
differential between a fixed and a variable price for crude oil and natural gas.
During 1997, the approximate monthly volume of crude oil sales subject to this
swap agreement is 15,800 barrels at a fixed price of $17.20. This agreement
reduces to approximately 13,200 barrels per month in 1998, 11,000 barrels per
month in 1999, 9,100 barrels per month in 2000 and 8,200 barrels per month in
2001 until November 1. The fixed price paid to the Company over this five year
period averages $17.55 per barrel. The natural gas component of this agreement
calls for approximately 54,000 MMBTU per month at a fixed price of $1.80 during
1997 with volumes decreasing to 37,000 MMBTU per month in 1998, 24,000 MMBTU per
month in 1999, 19,000 MMBTU per month in 2000, and 15,000 MMBTU per month in
2001 through October. The fixed price paid to the Company over this five year
period averages $1.84 per MMBTU.

The Company has also entered into two fixed price agreements, each
relating to approximately 3,750 net MMBTU per day of natural gas. The first of
these two agreements expires on March 31, 1997 and calls for a fixed price of
$1.52 per MMBTU being paid to the Company. The second agreement expires on
October 31, 1997 and provides a fixed price of $1.42 per MMBTU to the Company.

The Company has also recently entered into a costless collar relating
to 1,000 barrels a day of oil sales for the period February 1, 1997 through
December 31, 1997. This agreement guarantees a minimum price of $19.00 per
barrel to the Company and provides that any amount above $25.60 per barrel be
remitted by the Company to the counterparty to the agreement.

Substantially all of the remainder of the Company's crude oil and
natural gas is sold at current market prices under short term contracts, as is
customary in the industry. During the year ended December 31, 1996, seven
purchasers accounted for approximately 66% of the Company's crude oil and
natural gas sales. The Company believes that there are numerous other companies
available to purchase the Company's crude oil and natural gas and that the loss
of any or all of these purchasers would not materially affect the Company's
ability to sell crude oil and natural gas.

Risk Factors

Industry Conditions; Impact on Company's Profitability

The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for crude oil and natural gas.
Crude oil and natural gas prices can be extremely volatile and prior to 1996
were depressed by excess total domestic and imported supplies. While prices for
crude oil and natural gas increased during 1996 and have remained at these
levels during the first quarter of 1997, there can be no assurance that current
price levels for crude oil and natural gas can be sustained. Prices are also
affected by actions of state and local agencies, the United States and foreign
governments and international cartels. These external factors and the volatile
nature of the energy markets make it difficult to estimate future prices of
crude oil and natural gas. Any substantial or extended decline in the prices of
crude oil and natural gas would have a material adverse effect on the Company's
financial condition and results of operations, including reduced cash flow and
borrowing capacity. All of these factors are beyond the control of the Company.
Sales of crude oil and natural gas are seasonal in nature, leading to
substantial differences in cash flow at various times throughout the year.
Federal and state regulation of crude oil and natural gas production and
transportation, general economic conditions, changes in supply and changes in
demand all could adversely affect the Company's ability to produce and market
its crude oil and natural gas. If market factors were to change dramatically,
the financial impact on the Company could be substantial. The availability of
markets and the volatility of product prices are beyond the control of the
Company and thus represent a significant risk.

In addition, declines in crude oil and natural gas prices might,
under certain circumstances, require a write-down of the book value of the
Company's crude oil and natural gas properties. If such declines were severe
enough, they could result in the occurrence of an event of default under the
Company's outstanding indebtedness that could require the sale of some of the
Company's producing properties under unfavorable market conditions or require
the Company to seek additional equity capital. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources".

<PAGE>

Losses From Operations

The Company has experienced recurring losses. For the years ended
December 31, 1993, 1994 and 1995, the Company recorded net losses of $2.4
million, $2.4 million and $1.2 million, respectively. Although the Company had
net income of $ 1.5 million for the year ended December 31, 1996, there can be
no assurance that the Company will not experience operating losses in the
future.

Operating Hazards; Uninsured Risks

The nature of the crude oil and natural gas business involves certain
operating hazards such as crude oil and natural gas blowouts, explosions,
formations with abnormal pressures, cratering and crude oil spills and fires,
any of which could result in damage to or destruction of crude oil and natural
gas wells, destruction of producing facilities, damage to life or property,
suspension of operations, environmental damage and possible liability to the
Company. In accordance with customary industry practices, the Company maintains
insurance against some, but not all, of such risks and some, but not all, of
such losses. The occurrence of such an event not fully covered by insurance
could have a material adverse effect on the financial condition and results of
operations of the Company.

Leverage and Debt Service

The Company's level of indebtedness will have several important
effects on its future operations including (i) a substantial portion of the
Company's cash flow from operations will be dedicated to the payment of interest
on its indebtedness and will not be available for other purposes; (ii) covenants
contained in the Company's debt obligations will require the Company to meet
certain financial tests and other restrictions which will limit its ability to
borrow additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in its business, including
possibly limiting acquisition activities; and (iii) the Company's 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 may be limited.

As of December 31, 1996, the Company's total debt and stockholders'
equity were approximately $215.0 million and $35.7 million, respectively. In
addition, the Company had $20.0 million of unused borrowing capacity under the
Credit Facility (as defined below) at December 31, 1996. The Company intends to
incur additional indebtedness in the future in connection with acquiring,
developing and exploiting producing properties, although the Company's ability
to incur additional indebtedness may be limited by the terms of the indenture
(the "Indenture") governing its 11.5% Senior Notes Due 2004 (the "Notes") and
the Credit Facility.

The Company's ability to meet its debt service obligations and to
reduce its total indebtedness will be dependent upon the Company's future
performance, which will be subject to general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. Based upon the current level of operations
and the historical production of the producing properties and related assets
currently owned by the Company, the Company believes that its cash flow from
operations as well as borrowing capabilities will be adequate to meet its
anticipated requirements for working capital, capital expenditures, interest
payments, scheduled principal payments and general corporate or other purposes
for the foreseeable future. See the Company's Consolidated Financial Statements
and the notes thereto and "Management's Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and Capital Resources." No
assurance can be given, however, that the Company's business will continue to
generate cash flow from operations at or above current levels or that the
historical production of the producing properties and related assets currently
owned by the Company can be sustained in the future.

<PAGE>

If the Company is unable to generate cash flow from operations in the future to
service its debt, it may be required to refinance all or a portion of its
existing debt or to obtain additional financing. There can be no assurance that
such refinancing would be possible or that any additional financing could be
obtained. In addition, the Notes are subject to certain limitations on
redemption.

The Company's Credit Facility ("the Credit Facility") with Bankers
Trust Company, as agent, ING (U.S.) Capital Corporation, as co-agent and Union
Bank of California, N.A. (collectively the "Banks") contains a number of
covenants, including the following: (1) the ratio of current assets to current
liabilities (exclusive of any part of the loan which is current) shall not be
less than 1:1, (2) the ratio of (a) EBITDA to (b) Interest expense, measured as
of the last day of any calendar quarter for the twelve month period then ended,
shall not be less than 1.50 to 1.00 as of the last day of any calendar quarter
through June 30, 1997 or to be less than 1.75 to 1.00 as of the last day of any
calendar quarter after June 30, 1997 and (3) Consolidated Tangible Net Worth
must be greater than $30,000,000 at any time. The Credit Facility also contains
covenants related to maintaining corporate existence, maintaining title to all
of the collateral free and clear of all liens except for the Banks liens and
those permitted by the Banks, maintaining all mineral interests in good repair
and in compliance with all laws, maintaining insurance, paying all taxes, not
paying dividends except as required on the Company's Series 1995-B Preferred
Stock and not selling any of the collateral securing the loans. The Company is
currently in compliance with these covenants.

Restrictions Imposed by Terms of the Company's Indebtedness

The Indenture and the Credit Facility restrict, among other things,
the Company's ability to incur additional indebtedness, incur liens, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, merge or consolidate
with any other person or sell, assign, transfer, lease, convey or otherwise
dispose of all or substantially all of the assets of the Company. In addition,
the Credit Facility contains additional and more restrictive covenants. The
Indenture and the Credit Facility also require the Company to maintain specified
financial ratios and satisfy certain financial tests. The Company's ability to
meet such financial ratios and tests may be affected by events beyond its
control, and there can be no assurance that the Company will meet such ratios
and tests. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources." A breach of any of
these covenants could result in a default under the Indenture and/or the Credit
Facility. Upon the occurrence of an event of default under the Credit Facility,
the lenders thereunder could elect to declare all amounts outstanding under the
Credit Facility, together with accrued interest, to be immediately due and
payable. If the Company were unable to repay those amounts, such lenders could
proceed against the collateral granted to them to secure that indebtedness. If
the lenders under the Credit Facility acelerate the payment of such
indebtedness, there can be no assurance that the assets of the Company would be
sufficient to repay in full such indebtedness and the other indebtedness of the
Company, including the Notes. Substantially all of the Company's U.S. assets,
including, without limitation, working capital and interests in producing
properties and related assets owned by the Company, and the proceeds thereof are
pledged as security under the Credit Facility. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources."

Substantial Capital Requirements

The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas reserves. Historically, the Company has
financed these expenditures primarily with cash flow from operations, bank
borrowings and the offering of its equity securities. The Company believes that
it will have sufficient capital to finance planned capital expenditures. If
revenues or the Company's borrowing base under the Credit Facility decrease as a
result of lower crude oil and natural gas prices, operating difficulties or
declines in reserves, the Company may have limited ability to finance planned
capital expenditures in the future. There can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet these requirements. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources."

<PAGE>

Integration of Operations; Foreign Operations

The Company's future operations and earnings will be largely
dependent upon the Company's ability to integrate the operations of CGGS and the
Wyoming Properties into the previous operations of the Company. The operations
of CGGS and the Wyoming Properties vary in geography from that of the Company's
previous operations, and with respect to CGGS, to some extent, in scope and
type, from the Company's previous operations. There can be no assurance that the
Company will be able to successfully integrate such operations with those of the
Company, and a failure to do so would have a material adverse effect on the
Company's financial position, results of operations and cash flows.
Additionally, although the Company does not currently have any specific
acquisition plans, the need to focus management's attention on integration of
the new operations, as well as other factors, may limit the Company's ability to
successfully pursue acquisitions or other opportunities related to its business
for the foreseeable future. Also, successful integration of operations will be
subject to numerous contingencies, some of which are beyond management's
control. These contingencies include general and regional economic conditions,
prices for crude oil and natural gas, competition and changes in regulation.
Even if the Company is successful in integrating the new operations, the
acquisition of CGGS in particular has significantly increased the Company's
dependence on international operations, specifically those in Canada, and
therefore the Company is subject to various additional political, economic and
other uncertainties. Among other risks, the Company's operations are subject to
the risks of restrictions on transfers of funds, export duties and quotas,
domestic and international customs and tariffs, and changing taxation policies,
foreign exchange restrictions, political conditions and governmental
regulations. In addition, the Company will receive a substantial portion of its
revenue in Canadian dollars. As a result, fluctuations in the exchange rates of
the Canadian dollar with respect to the U.S. dollar could have an adverse effect
on the Company's financial position, results of operations and cash flows. The
Company may from time to time engage in hedging programs intended to reduce the
Company's exposure to currency fluctuations.

Future Availability of Natural Gas Supply

To obtain volumes of committed natural gas reserves to supply the
Canadian Abraxas Plants, the Company will contract to process natural gas with
various producers. Future natural gas supplies available for processing at the
Canadian Abraxas Plants will be affected by a number of factors that are not
within the Company's control, including the depletion rate of natural gas
reserves currently connected to the Canadian Abraxas Plants and the extent of
exploration for, production and development of, and demand for natural gas in
the areas in which the Company will operate. Long-term contracts will not
protect the Company from shut-ins or supply curtailments by natural gas
supplies. Although CGGS was historically successful in contracting for new
natural gas supplies and in renewing natural gas supply contracts as they
expired, there is no assurance that the Company will be able to do so on a
similar basis in the future.

Shares Eligible for Future Sale

At March 21, 1997, the Company had 5,732,101 shares of Common Stock
outstanding of which 854,052 shares were held by affiliates. Of the shares held
by non-affiliates, 1,330,000 shares were sold in November 1995 in a private
placement (the "Private Placement") of 1,330,000 units each consisting of one
share of Common Stock and one Contingent Value Right ("CVR"). In addition, at
March 21, 1997, the Company had 550,810 shares of Common Stock subject to
outstanding options granted under certain stock option plans (of which 149,482
shares were vested at March 21, 1997), 437,500 shares issuable upon exercise of
warrants and up to 1,995,000 shares of Common Stock issuable upon maturity of
the CVRs in November 1997. The actual number of shares issuable upon maturity of
the CVRs is dependent upon the difference between the target price (which is
$12.50 in 1997) and the median of the averages of the closing bid prices of the
Common Stock on the Nasdaq Stock Market during three consecutive 20-trading day
periods immediately preceding the maturity date.

All of the shares of Common Stock held by affiliates are restricted
or control securities under Rule 144 promulgated under the Securities Act of
1933, as amended (the "Securities Act"). The shares of the Common Stock issuable
upon exercise of the stock options have been registered under the Securities
Act. In addition, the Company has filed a registration statement covering the
shares of the Common Stock issued in the Private Placement and the shares of
Common Stock issuable upon maturity of the CVRs. All of such shares will be
offered only by means of a prospectus. The shares of the Common Stock issuable
upon exercise of the warrants are subject to certain registration rights and,
therefore, will be eligible for resale in the public market after a registration
statement covering such shares has been declared effective. Sales of shares of

<PAGE>

Common Stock under Rule 144 or pursuant to a registration statement could have a
material adverse effect on the price of the Common Stock and could impair the
Company's ability to raise additional capital through the sale of its equity
securities.

Competition

The Company encounters strong competition from major oil companies
and independent operators in acquiring properties and leases for the exploration
for, and production of, crude oil and natural gas. Competition is particularly
intense with respect to the acquisition of desirable undeveloped crude oil and
natural gas leases. The principal competitive factors in the acquisition of such
undeveloped crude oil and natural gas leases include the staff and data
necessary to identify, investigate and purchase such leases, and the financial
resources necessary to acquire and develop such leases. Many of the Company's
competitors have financial resources, staff and facilities substantially greater
than those of the Company. In addition, the producing, processing and marketing
of crude oil and natural gas is affected by a number of factors which are beyond
the control of the Company, the effect of which cannot be accurately predicted.

The principal raw materials and 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. The Company must
compete for such raw materials and resources with both major crude oil companies
and independent operators. Although the Company believes its current operating
and financial resources are adequate to preclude any significant disruption of
its operations in the immediate future, the continued availability of such
materials and resources to the Company cannot be assured.

The Company will 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. The Company's principal competitors will 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 the Company. Smaller local distributors may enjoy
a marketing advantage in their immediate service areas. The Company will compete
against other companies in its natural gas processing business both for supplies
of natural gas and for customers to which it will sell its 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.

Reliance on Estimates of Proved Reserves and Future Net Revenues; Depletion of
Reserves

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data set forth in this report represent only estimates. In
addition, the estimates of future net revenues from proved reserves of the
Company and the present value thereof are based upon certain 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 Present Value of Proved Reserves for the
crude oil and natural gas properties described in this report 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, 1996. The average sales prices as of
such dates used for purposes of such estimates were $23.19 per Bbl of crude oil,
$16.31 per Bbl of NGLs and $2.96 per Mcf of natural gas. Also assumed is the
Company's making future capital expenditures of approximately $23.1 million in
the aggregate necessary to develop and realize the value of proved undeveloped
reserves on its properties. Any significant variance in these assumptions could
materially affect the estimated quantity and value of reserves set forth herein.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources" and "Business - Reserve
Information."

<PAGE>

Certain Business Risks

The Company intends to continue acquiring producing crude oil and
natural gas properties or companies that own such properties. Although the
Company performs a review of the acquired properties that it believes is
consistent with industry practices, such reviews are inherently incomplete. It
generally is not feasible to review in depth every individual property involved
in each acquisition. Ordinarily, the Company will focus its review efforts on
the higher-valued properties and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal
existing or potential problems nor will it permit the Company to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken. Furthermore, the Company must
rely on information, including financial, operating and geological information,
provided by the seller of the properties without being able to verify fully all
such information and without the benefit of knowing the history of operations of
all such properties.

In addition, a high degree of risk of loss of invested capital exists
in almost all exploration and development activities which the Company
undertakes. No assurance can be given that crude oil or natural gas will be
discovered to replace reserves currently being developed, produced and sold, or
that if crude oil or natural gas reserves are found, they will be of a
sufficient quantity to enable the Company to recover the substantial sums of
money incurred in their acquisition, discovery and development. Drilling
activities are subject to numerous risks, including the risk that no
commercially productive crude oil or natural gas reservoirs will be encountered.
The cost of drilling, completing and operating wells is often uncertain. The
Company's operations may be curtailed, delayed or cancelled as a result of
numerous factors including title problems, weather condition, compliance with
governmental requirements and shortages or delays in the delivery of equipment.
The availability of a ready market for the Company's natural gas production
depends on a number of factors, including, without limitation, the demand for
and supply of natural gas, the proximity of natural gas reserves to pipelines,
the capacity of such pipelines and governmental regulations.

Depletion of Reserves

The rate of production from crude oil and natural gas properties
declines as reserves are depleted. Except to the extent the Company acquires
additional properties containing proved reserves, conducts successful
exploration and development activities or, through engineering studies,
identifies additional behind-pipe zones or secondary recovery reserves, the
proved reserves of the Company will decline as reserves are produced. Future
crude oil and natural gas production is therefore highly dependent upon the
Company's level of success in acquiring or finding additional reserves. See " -
Certain Business Risks."

The Company's ability to continue to acquire producing properties or
companies that own such properties assumes that major integrated oil companies
and independent oil companies will continue to divest many of their crude oil
and natural gas properties. There can be no assurance, however, that such
divestitures will continue or that the Company will be able to acquire such
properties at acceptable prices or develop additional reserves in the future. In
addition, under the terms of the Indenture and the Credit Agreement, the
Company's ability to obtain additional financing in the future for acquisitions
and capital expenditures may be limited.

Title to Properties

As is customary in the crude oil and natural gas industry, the
Company performs a minimal title investigation before acquiring undeveloped
properties, which generally consists of obtaining a title report from legal
counsel covering title to the major properties and due diligence reviews by
independent landmen of the remaining properties. The Company believes that it
has satisfactory title to such properties in accordance with standards generally
accepted in the crude oil and natural gas industry. A title opinion is obtained
prior to the commencement of any drilling operations on such properties. The
Company's properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens, none of
which the Company believes materially interferes with the use of, or affect the
value of, such properties. All of the Company's United States properties are
also subject to the liens of the Banks.

<PAGE>

Government Regulation

The Company's business is subject to certain federal, state and local
laws and regulations relating to the exploration for and development, production
and marketing of crude oil and natural gas, as well as environmental and safety
matters. Such laws and regulations have generally become more stringent in
recent years, often imposing greater liability on a larger number of potentially
responsible parties. Because the requirements imposed by such laws and
regulations are frequently changed, the Company is unable to predict the
ultimate cost of compliance with such requirements. There is no assurance that
laws and regulations enacted in the future will not adversely affect the
Company's financial condition and results of operations.

Dependence on Key Personnel

The Company depends to a large extent on Robert L. G. Watson, its
Chairman of the Board, President and Chief Executive Officer, for its management
and business and financial contacts. The unavailability of Mr. Watson would have
a materially adverse effect on the Company's business. The Company's success is
also dependent upon its ability to employ and retain skilled technical
personnel. While the Company has not to date experienced difficulties in
employing or retaining such personnel, its failure to do so in the future could
adversely affect its business. The Company has entered into employment
agreements with Mr. Watson and each of the Company's vice presidents. The
employment agreements terminate on December 31, 1997 except that the term may be
extended for an additional year if by December 1 of the prior year neither the
Company nor the officer has given notice that it does not wish to extend the
term. Except in the event of a change in control, Mr. Watson's and each of the
vice president's employment is terminable at will by the Company for any reason,
without notice or cause.

Limitations on the Availability of the Company's Net Operating Loss
Carryforwards

At December 31, 1996, the Company had, subject to the limitations
discussed below, $17.5 million of net operating loss carryforwards for tax
purposes, of which approximately $16.1 million are available for utilization
without limitation. These loss carryforwards will expire from 2002 through 2010
if not 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 of the Internal Revenue Code of 1986, as amended (Section
382), occurred in December 1991. Accordingly, it is expected that the use of net
operating loss carryforwards generated prior to December 31, 1991 of $4.9
million will be limited to approximately $235,000 per year. During 1992 the
Company acquired 100% of the outstanding capital stock of an unrelated
corporation. The use of the net operating loss carryforwards of $1.1 million of
the unrelated corporation 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 stock, an additional ownership change under Section 382 occurred in
October 1993. Accordingly, it is expected that the use of the $8.2 million of
net operating loss carryforwards generated through October 1993 will be limited
to approximately $1 million per year subject to the lower limitations described
above and $7.2 million in the aggregate. Future changes in ownership may further
limit the use of the Company's carryforwards. 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 $5.7 million and
$5.7 million for deferred tax assets at December 31, 1996 and 1995,
respectively.

Regulation of Crude Oil and Natural Gas Activities

Regulatory Matters

The Company's operations are affected from time to time in varying
degrees by political developments and federal, state, provincial and local laws
and regulations. In particular, oil and gas production operations and economics
are, or in the past have been, affected by 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.

<PAGE>

Price Regulations. In the recent past, maximum selling prices for
certain categories of crude oil, natural gas, condensate and NGLs were subject
to federal regulation. In 1981, all federal price controls over sales of crude
oil, condensate and NGLs were lifted. Effective January 1, 1993, the Natural Gas
Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for
all "first sales" of natural gas, which includes all sales by the Company of its
own production. As a result, all sales of the Company's domestically produced
crude oil, natural gas, condensate and NGLs may be sold at market prices, unless
otherwise committed by contract.

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. As is the case with crude
oil, natural gas exports for a term of less than two years must be made pursuant
to an NEB order, or, in the case of exports for a longer duration, pursuant to
an NEB license and Governor in Council approval.

The government of Alberta also regulates the volume of natural gas
that may be removed from Alberta 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.

Natural Gas Regulation. Historically, interstate pipeline companies
generally acted as wholesale merchants by purchasing natural gas from producers
and reselling the 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 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 makes natural gas sales as a merchant, it does so pursuant to private
contracts in direct competition with all of the sellers, such as the Company;
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." In subsequent orders, the FERC largely affirmed the
major features of Order 636 and denied a stay of the implementation of the new
rules pending judicial review. By the end of 1994, the FERC had concluded the
Order 636 restructuring proceedings, and, in general, accepted rate filings
implementing Order 636 on every major interstate pipeline. However, even through
the implementation of Order 636 on individual interstate pipelines is
essentially complete, many of the individual pipeline restructuring proceedings,
as well as Order 636 itself and the regulations promulgated thereunder, are
subject to pending appellate review and could possibly be changed as a result of
future court orders. The Company cannot predict whether the FERC's orders will
be affirmed on appeal or what the effects will be on its business.

In recent years the FERC also has pursued a number of other
important policy initiatives which could significantly affect the marketing of
natural gas. Some of the more notable of these regulatory initiatives include
(I) 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

<PAGE>

nonregulated affiliates), (ii) the completion of rule-making involving the
regulation of pipelines with marketing affiliates under Order No. 497, (iii) the
FERC's ongoing efforts to promulgate standards for pipeline electronic bulletin
boards and electronic data exchange, (iv) a generic inquiry into the pricing of
interstate pipeline capacity, (v) efforts to refine the FERC's regulations
controlling operation of the secondary market for released pipeline capacity,
and (vi) a policy statement regarding market based rates and other
non-cost-based rates for interstate pipeline transmission and storage capacity.
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 as a result of the
monopolization of those facilities by their new, unregulated owners. The FERC
has attempted to address some of these concerns in its orders authorizing such
"spin downs," but it remains to be seen what effect these activities will have
on access to markets and the cost to do business. As to all of these recent FERC
initiatives, the ongoing, or, in some instances, preliminary evolving nature of
these regulatory initiatives makes it impossible at this time to predict their
ultimate impact on the Company's business.

Recent orders of the FERC 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." The
Company transports certain of its natural gas through gathering facilities owned
by others, including interstate pipelines, under existing long term contractual
arrangements. With respect to item (i) in the preceding paragraph, on May 27,
1994, the FERC issued orders in the context of the "spin off" or "spin down" of
interstate pipeline owned gathering facilities. A "spin off" is a FERC-approved
sale of such facilities to a non-affiliate. A "spin down" is the transfer by the
interstate pipeline of its gathering facilities to an affiliate. A number of
spin offs and spindowns have been approved by the FERC and implemented. The FERC
held that it retains jurisdiction over gathering provided by interstate
pipelines, but that it generally does not have jurisdiction over pipeline
gathering affiliates, except in the event of affiliate abuse (such as actions by
the affiliate undermining open and nondiscriminatory access to the interstate
pipeline). These orders require nondiscriminatory access for all sources of
supply and prohibit the tying of pipeline transportation service to any service
provided by the pipeline's gathering affiliate. On November 30, 1994, the FERC
issued a series of rehearing orders largely affirming the May 27, 1994 orders.
The FERC now requires interstate pipelines to not only seek authority under
Section 7(b) of the Natural Gas Act of 1938 (the "NGA") to abandon certificated
facilities, but also to seek authority under Section 4 of the NGA to terminate
service from both certificated and uncertificated facilities. On December 31,
1994, an appeal was filed with the U.S. Court of Appeals for the D.C. Circuit to
overturn three of the FERC's November 30, 1994, orders. The Company cannot
predict what the ultimate effect of the FERC's orders pertaining to gathering
will have on its production and marketing, or whether the Appellate Court will
affirm the FERC's orders on these matters.

State and Other Regulation. All of the jurisdictions in which the
Company owns producing crude oil and natural gas properties have statutory
provisions regulating the exploration for and production of crude oil and
natural gas, including provisions requiring permits for the drilling of wells
and maintaining bonding requirements in order to drill or operate wells and
provisions relating to the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are
drilled and the plugging and abandoning of wells. The Company's 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 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 allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state 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 these regulations is to limit
the amounts of crude oil and natural gas the Company can produce from its wells,
and to limit the number of wells or the location at which the Company can drill.

<PAGE>

State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take
requirements, but does not generally entail rate regulation. 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, Oklahoma recently enacted a prohibition against discriminatory
gathering rates and certain Texas regulatory officials have expressed interest
in evaluating similar rules.

Royalty Matters

United States. By a letter dated May 3, 1993, directed to thousands
of producers holding interests in federal leases, the United States Department
of the Interior (the "DOI") announced its interpretation of existing federal
leases to require the payment of royalties on past natural gas contract
settlements which were entered into in the 1980s and 1990s to resolve, among
other things, take-or-pay and minimum take claims by producers against pipelines
and other buyers. The DOI's letter sets forth various theories of liability, all
founded on the DOI's interpretation of the term "gross proceeds" as used in
federal leases and pertinent federal regulations. In an effort to ascertain the
amount of such potential royalties, the DOI sent a letter to producers on June
18, 1993, requiring producers to provide all data on all natural gas contract
settlements, regardless of whether natural gas produced from federal leases were
involved in the settlement. The Company received a copy of this information
demand letter. In response to the DOI's action, in July 1993, various industry
associations and others filed suit in the United States District Court for the
Northern District of West Virginia seeking an injunction to prevent the
collection of royalties on natural gas contract settlement amounts under the
DOI's theories. The lawsuit, styled "Independent Petroleum Association v.
Babbitt," was transferred to the United States District Court in Washington,
D.C. On June 4, 1995, the Court issued a ruling in this case holding that
royalties are payable to the United States on natural gas contract settlement
proceeds in accordance with the Minerals Management Service's May 3, 1993,
letter to producers. This ruling was appealed and is now pending in the D.C.
Circuit Court of Appeals. The DOI's claim in a bankruptcy proceeding against a
producer based upon an interstate pipeline's earlier buy-out of the producer's
natural gas sale contract was rejected by the Federal Bankruptcy Court in
Lexington, Kentucky, in a proceeding styled "Century Offshore Management Corp."
While the facts of the Court's decision do not involve all of the DOI's
theories, the Court found on those at issue that the DOI's theories were without
legal merit, and the Court's reasoning suggests that the DOI's other claims are
similarly deficient. This decision was upheld in the District Court and is now
on appeal in the Sixth Circuit Court of Appeals. Because both the "Independent
Petroleum Association v. Babbitt" and "Century Offshore Management Corp."
decisions have been appealed, and because of the complex nature of the
calculations necessary to determine potential additional royalty liability under
the DOI's theories, it is impossible to predict what, if any, additional or
different royalty obligation the DOI may assert or ultimately be entitled to
recover with respect to any of the Company's prior natural gas contract
settlements.

Canada. 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 Canada, Alberta and Saskatchewan
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.

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 qualifying development wells that were spudded
on or after November 1, 1991, and prior to August 1, 1993 (or spudded in August
but licensed prior thereto) are eligible for a 12-month royalty exemption up to
a maximum of CDN$400,000. Exploration wells spudded on or after November 1, 1991
and prior to April 1, 1992, or if drilled in northern Alberta or the Foothills
area of Alberta prior to April 1, 1993, are entitled to a 24-month exemption to
a maximum of CDN$1.0 million. A 24-month royalty reduction (up to December 31,
1996) is available for crude oil produced from qualifying horizontal extensions
commenced prior to January 1, 1995. Crude oil produced from horizontal
extensions commenced at least five years after the well was originally spudded
may also qualify for a royalty reduction. Wells drilled prior to September 1,
1990, and reactivated between November 1, 1991 and October 1, 1992, having had

<PAGE>

no production between September 1, 1990 and November 1, 1991, are entitled to a
five year royalty exemption to a maximum of 4,000 cubic metres. An 8,000 cubic
metres exemption is available to production from a well that has not produced
for a 12-month period, if resuming production in October, November or December
of 1992 or January of 1993, or for a 24-month period if resuming production
after January 31, 1993. 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 $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 also introduced the Third Tier Royalty with a
base rate of 10% and a rate cap of 25% from oil pools discovered after September
30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a
rate cap of 30% and for old oil a base rate of 10% and a rate cap of 35%.

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 continues to be 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.

Crude oil and natural gas royalty holidays and reductions for
specific wells reduce the amount of Crown royalties paid to the provincial
governments. The ARTC program provides a rebate on Crown royalties paid in
respect of eligible producing properties.

The Government of Saskatchewan revised its fiscal regime for the oil
and gas industry effective January 1, 1994. Some royalties on wells existing as
of that date will remain unchanged and therefore subject to various periods of
royalty/tax reduction. While a number of incentives were eliminated or reduced
(such as incentives for vertical infill wells and lower cost horizontal wells),
new incentive programs were initiated to encourage greater exploration and
development activity in the province. The new fiscal regime provides an
incentive to encourage the drilling of new vertical oil wells through a revised
royalty/tax structure for new vertical oil wells and incremental production from
new or expanded water flood projects. This "third tier" Crown royalty rate is
price sensitive and varies between heavy and non-heavy oil (from a minimum of
10% for heavy oil at a base price to a maximum of 35% for non-heavy oil at a
price above the base price). Previous time-based royalty/tax holidays applicable
to vertically drilled oil wells have been replaced with volume-based royalty/tax
reduction incentives in which a maximum royalty of 5% will apply to various
volumes depending on the depth and nature of the well (up to 25,000 cubic metres
of oil in the case of deep exploratory wells). The maximum royalty applicable to
the first 12,000 cubic metres of oil has been increased from 5% to 10% for
production from certain horizontal wells. In addition, royalty/tax holidays for
deep horizontal oil wells have been replaced with a 25,000 cubic metres volume
incentive (5% maximum royalty). Oil production from qualifying reactivated oil
wells are subject to a maximum new royalty rate of 5% for the first five years
following re-activation in the case of wells reactivated after 1993 and shut-in
or suspended prior to January 1, 1993. With respect to qualifying exploratory
natural gas wells, the first 25 million cubic metres of natural gas produced
will be subject to an incentive maximum royalty rate of 5%.

<PAGE>

Environmental Matters

The Company's operations are subject to numerous federal, state, and
local laws and regulations controlling the discharge of materials into the
environment or otherwise relating to the protection of the environment,
including the Comprehensive Environment Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Federal Superfund Law." Such laws and
regulations, among other things, impose absolute liability upon the lessee under
a lease for the cost of clean up of pollution resulting from a lessee's
operations, subject the lessee to liability for pollution damages, may require
suspension or cessation of operations in affected areas, and impose restrictions
on the injection of liquids into subsurface aquifers that may contaminate
groundwater. The Company maintains insurance against costs of clean-up
operations, but it's not fully insured against all such risks. A serious
incident of pollution may, as it has in the past, also result in the DOI
requiring lessees under federal leases to suspend or cease operation in the
affected area. In addition, the recent trend toward stricter standards in
environmental legislation and regulation may continue. For instance, legislation
has been proposed in Congress from time to time that would reclassify certain
crude oil and natural gas production wastes as "hazardous wastes" which would
make the reclassified exploration and production wastes subject to much more
stringent handling, disposal, and clean up requirements. If such legislation
were to be enacted, it could have a significant impact on the Company's
operating costs, as well as the crude oil and natural gas industry in general.
State initiatives to further regulate the disposal of crude oil and natural gas
wastes are also pending in certain states, and these various matters could have
a similar impact on the Company.

The Company's Canadian operations are also subject to environmental
regulation pursuant to local, provincial and federal legislation. Canadian
environmental legislation provides for restrictions and prohibitions on releases
or emissions of various substances produced in association with certain crude
oil and natural gas industry operations and 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. Environmental legislation in Alberta has undergone a major revision and
has been consolidated in the Environmental and Enhancement Act . Under the new
Act, environmental standards and compliance for releases, clean-up and reporting
are stricter. Also, the range of enforcement actions available and the severity
of penalties have been significantly increased. These changes will have
incremental effect on the cost of conducting operations in Alberta.

The Company is not currently involved in any administrative or
judicial proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations which would have a material
adverse effect on the Company's financial position or results of operations.

Employees

As of March 21, 1997, Abraxas and its subsidiaries had 64 full-time
employees, including two executive officers, four non-executive officers, four
petroleum engineers, one landman, two geologists, 24 secretarial, accounting and
clerical personnel and 27 field personnel. Additionally, Abraxas also retains
contract pumpers on a month-to-month basis. Abraxas retains independent
geologic, geophysical and engineering consultants from time to time on a limited
basis and expects to continue to do so in the future.

Recent Activities

In January 1997, Canadian Abraxas sold its interest in the Hoole Area
(the "Hoole Area") for approximately $9.3 million. The Hoole Area consists of
9,728 gross acres (3,311 net acres) and 6.0 gross wells (3.2 net wells), none of
which are operated by Canadian Abraxas. As of January 1, 1997, the Hoole Area
natural gas properties had total proved reserves of 1,268.0 MBOE with a Present
Value of Proved Reserves of $11.2 million, all of which was attributable to
proved developed reserves. The Hoole Area natural gas processing plant had
aggregate net natural gas processing capacity of 32.0 MMCF per day at December
31, 1996. For the twelve months ended December 31, 1996, the Hoole Area natural
gas processing plant processed an average of 18.9 gross MMCF (9.5 net MMCF ) of
natural gas per day, of which 4.4% (2.2% net) was custom processed for third
parties.

<PAGE>

Item 2. Properties.

Exploratory and Developmental Acreage

Abraxas' 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 Abraxas'
interest in developed and undeveloped acreage as of December 31, 1996:
<TABLE>
<CAPTION>

Developed and Undeveloped Acreage
As of December 31, 1996

Developed Acreage(1) Undeveloped Acreage(2)
State Gross Acres(3) Net Acres(4) Gross Acres(3) Net Acres(4)

<S> <C> <C> <C> <C>
Canada 88,085(5) 47,140(5) 92,284 41,005
Texas 41,115 23,153 22,477 13,864
Wyoming 5,239 3,620 14,020 9,476
N. Dakota 1,864 1,021 -- --
Alabama 720 23 -- --
Kansas 640 142 -- --
Montana 320 10 -- --
New Mexico 320 42 -- --
TOTAL 138,303 75,151 128,781 64,345
</TABLE>

(1) Developed acreage consists of acres spaced or assignable to productive
wells.
(2) Undeveloped acreage is considered to be those leased acres on which wells
have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether
or not such acreage contains proved reserves.
(3) Gross acres refers to the number of acres in which Abraxas owns a working
interest.
(4) Net acres represents the number of acres attributable to an owner's
proportionate working interest and/or royalty interest in a lease (e.g., a
50% working interest in a lease covering 320 acres is equivalent to 160
net acres).
(5) Includes 9,728 gross acres and 3,311 net acres in the Hoole Area. See
"Business - Recent Activities".

Productive Wells

The following table sets forth the total gross and net productive
wells of Abraxas, expressed separately for crude oil and natural gas, as of
December 31, 1996:

Productive Wells(1)
- --------------------------------------------------------------------------

STATE/ CRUDE NATURAL
COUNTRY OIL GAS
- --------------------------------------------------------------------------

Gross(2) Net(3) Gross(2) Net(3)

Texas 258.0 180.6 98.0 63.6
Canada(4) 15.0 12.5 132.0 55.2(4)
Kansas 4.0 0.8 -- --
N. Dakota 4.0 1.7 -- --
Alabama 2.0 0.1 1.0 0.1
Montana 1.0 0.1 -- --
Wyoming 1.0 0.1 29.0 21.3
New Mexico -- -- 1.0 0.1
----- ----- ----- -----
TOTAL 285.0 195.9 261.0 140.3
- ------------

(1) Productive wells are producing wells and wells capable of production.

<PAGE>

(2) A gross well is a well in which Abraxas owns a working interest. The
number of gross wells is the total number of wells in which Abraxas owns a
working interest.
(3) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
Abraxas' fractional working interest owned in gross wells.
(4) Includes 6.0 gross wells and 3.2 net wells in the Hoole Area. See
"Business - Recent Activities".

Substantially all of Abraxas' existing crude oil and natural gas
properties are pledged to secure Abraxas' indebtedness under its' credit
agreement. See "Management's Discussion of Financial Condition and Results of
Operations--Liquidity and Capital Resources".

Reserves Information

The crude oil and natural gas reserves of Abraxas have been estimated
as of January 1, 1997, January 1, 1996 and January 1, 1995 and of Canadian
Abraxas as of January 1, 1997, by DeGolyer & MacNaughton, of Dallas, Texas.
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 involved 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 Abraxas' crude oil, natural gas liquids and natural gas reserves as
of January 1, 1997, January 1, 1996 and January 1, 1995.

ESTIMATED PROVED RESERVES
----------------------------------------
Proved Proved Total
Developed Undeveloped Proved
----------- ----------- -----------
As of January 1, 1995
Crude Oil, Bbls 3,616,510 3,032,818 6,649,328
Natural Gas Liquids, Bbls 2,089,168 417,994 2,507,162
Natural Gas, Mcf 48,973,212 18,605,881 67,579,093

As of January 1, 1996
Crude Oil, Bbls 3,991,804 1,516,012 5,507,816
Natural Gas Liquids, Bbls 2,007,777 751,649 2,759,426
Natural Gas, Mcf 44,025,782 10,542,825 54,568,607

As of January 1, 1997 (1)
Crude Oil, Bbls 7,871,308(2) 1,930,240 9,801,548(2)
Natural Gas Liquids, Bbls 7,089,755 1,144,341 8,234,096
Natural Gas, Mcf 157,660,157 19,599,554 177,259,711

(1) Includes reserves of Canadian Abraxas (Including 1,268 MBOE
attributable to the Hoole Area).

(2) Includes 120,400 barrels of crude oil reserves owned by Cascade of
which 57,600 barrels are applicable to the minority interest's share
of the reserves.

There are numerous uncertainties inherent in estimating crude oil and
natural gas reserves and their estimated values, including many factors beyond
the control of the producer. The reserve data set forth herein represent only
estimates. Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
As a result, estimates of different engineers often vary. In addition, estimates
of reserves are subject to revision by the results of drilling, testing and
production subsequent to the date of such estimates. Accordingly, reserve
estimates are often different from the quantities of crude oil and natural gas
that are ultimately recovered. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they are based.

<PAGE>

In general, the volume of production from crude oil and natural gas
properties declines as reserves are depleted. Except to the extent the Company
acquires properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves of the
Company will decline as reserves are produced. The Company's future crude oil
and natural gas production is therefore highly dependent upon its level of
success in acquiring or finding additional reserves.

The Company files reports of its 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 the net crude oil, net natural gas liquids
and net natural gas production for Abraxas, 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, 1996:

1996 1995 1994
--------- --------- ---------
Crude oil production (Bbls) 425,188 401,445 355,710
Natural gas production (Mcf) 6,350,069 3,552,671 2,392,855
Natural gas liquids
Production (Bbls) 299,509 143,380 113,157
Average sales price per
Bbl of crude oil($) $20.85 $17.16 $15.47
Average sales price per
Mcf of natural gas($) $1.97 $1.47 $1.85
Average sales price per
Bbl. of natural gas liquids $14.55 $10.83 $10.54
Average cost of production
($) per BOE produced (1) $3.28 $3.81 $4.26

(1) Oil and gas were combined by converting gas to a barrel oil equivalent
("BOE") on the basis of 6 Mcf gas =1 Bbl of oil. Production costs include
direct operating costs, ad valorem taxes and gross production taxes.

<PAGE>

Drilling Activities

The following table sets forth Abraxas' gross and net working
interests in exploratory, development, and service wells drilled during the
three years ended December 31, 1996:
<TABLE>
<CAPTION>

1996 1995 1994
--------------------- --------------------- -----------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Exploratory(3) - - - - - -
Productive(4) - - - - - -

Crude oil 2.0 1.2 1 .72 - -
Natural gas 2.0 1.2 - - 1 2
Dry holes(5) 4.0 1.4 1 1 2 5
--------- -------- ---------- -------- --------- --------
Total 8.0 3.8 2 1.72 3 7
========= ======== ========== ======== ========= ========
Development(6)
Productive - - - -
Crude oil 20.0 15.8 12 9.1 3 1.5
Natural gas 10.0 3.7 2 .6 6 2.1
Service(7) 1.0 1.0 - - - -
Dry holes(5) - - 1 .3 - -
--------- -------- ---------- -------- --------- --------
Total 31.0 20.5 15 10.0 9 3.6
========= ======== ========== ======== ========= ========
</TABLE>
- ------------------

(1) A gross well is a well in which Abraxas owns an interest.
(2) 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).
(3) An exploratory well is 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.
(4) A productive well is an exploratory or a development well that is not a
dry hole.
(5) A dry hole is an exploratory or development well found to be incapable of
producing either crude oil or natural gas in sufficient quantities to
justify completion as a crude oil or natural gas well.
(6) A development well is 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) noted to be productive for the purpose of extracting
proved crude oil or natural gas reserves.
(7) A service well is used for water injection in secondary recovery projects
or for the disposal of produced water.

<PAGE>

Office Facilities

The Company's executive and administrative offices are located at 500
N. Loop 1604 East, Suite 100, San Antonio, Texas 78232. The Company owns a 16%
limited partnership interest in the Partnership which owns the office building.
The Company also has an office in Midland, Texas. These offices, consisting of
approximately 12,650 square feet in San Antonio and 960 square feet in Midland,
are leased until March 2006 from unaffiliated parties at an aggregate rate of
$13,166 per month.

Other Properties

The Company owns 10 acres of land, an office building, shop,
warehouse and house in Sinton, Texas, 160 acres of land in Coke County, Texas
and a 50% interest in approximately 2.0 acres of land in Bexar County, Texas.
All three properties are used for the storage of tubulars and production
equipment. The Company also owns 20 vehicles which are used in the field by
employees.

Item 3. Legal Proceedings

From time to time, the Company is involved in litigation relating to
claims arising out of its operations in the normal course of business. As of
March 21, 1997, 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.

Item 4. Submission of Matters to a Vote of Security Holders

No matter was submitted to a vote of security holders of the Company
during the fourth quarter of the fiscal year ended December 31, 1996.

Item 4a. Executive Officers of the Company

Certain information is set forth below concerning the executive
officers of the Company, each of whom has been selected to serve until the 1997
annual meeting of directors and until his successor is duly elected and
qualified.

Robert L. G. Watson, age 46, has served as President and a director
of the Company since 1977. Prior to joining the Company, Mr. Watson was employed
in various petroleum engineering positions. From 1970 to 1972, Mr. Watson was
employed by DeGolyer & MacNaughton, an independent petroleum engineering firm
and from 1972 through 1977, Mr. Watson was employed by Tesoro Petroleum
Corporation, a crude oil and natural gas exploration and production company. Mr.
Watson received the degree of Bachelor of Science in Mechanical Engineering from
Southern Methodist University in 1972 and Master of Business Administration from
the University of Texas at San Antonio in 1974.

Chris E. Williford, age 45, was elected Vice President, Treasurer and
Chief Financial Officer of the Company in January 1993, and as Executive Vice
President and a director of the Company in May 1993. Prior to joining the
Company, 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 degree of Bachelor of Science in Business
Administration from Pittsburg State University in 1973.

<PAGE>

PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.

Market Information

Abraxas Common Stock is traded on the NASDAQ Stock Market and
commenced trading on May 7, 1991. The following table sets forth certain
information as to the high and low bid quotations quoted on NASDAQ for 1994,
1995 and 1996. Information with respect to over-the-counter bid quotations
represents prices between dealers, does not include retail mark-ups, mark-downs
or commissions, and may not necessarily represent actual transactions.

Period High Low
---------- ------ -----
1994
First Quarter........................$13.50 $9.00
Second Quarter........................13.50 9.75
Third Quarter.........................13.13 9.00
Fourth Quarter .......................11.50 9.25
1995
First Quarter........................$10.25 $8.50
Second Quarter.........................9.63 8.00
Third Quarter..........................8.88 7.94
Fourth Quarter.........................8.88 6.13
1996
First Quarter.........................$7.75 $4.13
Second Quarter.........................7.25 5.00
Third Quarter..........................7.13 4.75
Fourth Quarter........................10.50 5.75

Holders

As of March 21, 1997 Abraxas had 5,732,101 shares of common stock
outstanding and had approximately 1,900 Stockholders of record.

Dividends

Abraxas has not paid any cash dividends on its Common Stock and it is
not presently determinable when, if ever, Abraxas will pay cash dividends in the
future. The Credit Agreement and the Indenture, prohibits the payment of cash
dividends and stock dividends on the Company's Common Stock. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Liquidity and Capital Resources".

<PAGE>

Item 6. Selected Financial Data

The following selected financial data are derived from the
consolidated financial statements of Abraxas. The data should be read in
conjunction with the consolidated financial statements, related notes, and other
financial information included herein.
<TABLE>
<CAPTION>

Year Ended December 31,
---------------------------------------------------------
1996 1995 1994 1993 1992
--------- -------- -------- -------- -------
(In thousands, except per share data)

<S> <C> <C> <C> <C> <C>
Total revenue $ 26,653 $13,817 $11,349 $ 7,494 $ 2,691
Income (loss) from continuing operations $ 1,940 $(1,209) $ 113 $(1,580) $(1,072)
Income (loss) per common share and common
equivalent from continuing operations $ .23 $ (.34) $ .02 $ (.91) $ (1.23)
Weighted average shares
outstanding 6,794 4,635 4,310 1,947 1,074
Total Assets $304,842 $85,067 $75,361 $43,396 $18,017
Long-term debt $215,032 $41,601 $41,296 $12,529 $ 6,602
Total shareholders' equity $ 35,656 $37,062 $28,502 $25,143 $ 2,233

</TABLE>

Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations

The following is a discussion of the Company's consolidated financial
condition, results of operations, liquidity and capital resources. This
discussion should be read in conjunction with the Consolidated Financial
Statements of the Company and the Notes thereto. See "Financial Statements".

Results of Operations

The factors which most significantly affect the Company's results of
operations are (1) the sales prices of crude oil, natural gas liquids and
natural gas, (2) the level of total sales volumes of crude oil, natural gas
liquids and natural gas, (3) the level of and interest rates on borrowings and
(4) the level and success of exploration and development activity.

Selected Operating Data. The following table sets forth certain
operating data of the Company for the periods presented:

Years Ended December 31
1996 1995 1994
Operating revenue (in thousands):
Natural gas sales..................... $12,526 $6,889 $5,501
Crude oil sales........................ 8,864 5,218 4,420
Natural gas liquid sales.............. 4,359 1,553 1,193
Gas Processing Revenue................. 600 -- --
Other.................................. 304 157 235
------- ------- -------
Total operating revenue................ $26,653 $13,817 $11,349
======= ======= =======
Operating income (loss) in thousands... $8,826 $2,883 $2,923
Natural gas production (Mmcfs).......... 6,350.0 3,552.7 2,392.9
Crude oil production (Mbbls)............ 425.2 401.4 355.7
Natural gas liquids production (Mbbls).. 299.5 143.4 113.2
Average natural gas sales price ($/Mcf). $1.97 $1.47 $1.85
Average crude oil sales price ($/Bbl)... $20.85 $17.16 $15.47
Average natural gas liquids sales price
($/Bbl)............................... $14.55 $10.83 $10.54

<PAGE>

Comparison of Year Ended December 31, 1996 to Year Ended December 31, 1995

Operating Revenue. During the year ended December 31, 1996, operating
revenue from crude oil, natural gas and natural gas liquids sales, and natural
gas processing revenues increased 92% from $13.7 million in 1995 to $26.3
million. This increase was primarily attributable to increased crude oil and
natural gas liquids sales volumes of 33.0% and natural gas sales volumes of
78.7% which was attributable to increased production from the producing
properties that the Company owned for the entire year as well as producing
properties acquired during the year. This increase more than offset the loss of
operating revenue from the Portilla and Happy fields during the portion of the
year that the Company did not own the properties. During 1995, the Portilla and
Happy Fields contributed $4.6 million in operating revenue compared to $2.0
million in 1996. Crude oil and NGLs sales volumes increased from 545 MBbls to
725 MBbls, from 1995 to 1996 and natural gas sales volumes increased from 3.6
BCF to 6.4 BCF, from 1995 to 1996 as a result of increased production volumes
from the Company's properties other than Portilla and Happy in 1996 as compared
to 1995 and the acquisitions of the Wyoming Properties, the stock of CGGS and
the Company's ongoing development drilling program. Portilla and Happy
contributed 226.0 MBbls of crude oil and NGLs (41.5% of Company total) and 492.6
MMcf of natural gas (13.9% of Company total) during 1995 as compared to 91.7
MBbls of crude oil and NGLs (12.7% of Company total) and 215.6 MMcf of natural
gas (3.4% of Company total) for 1996. Average sales prices were $20.85 per Bbl
of crude oil, $14.55 per Bbl of natural gas liquids and $1.97 per Mcf of natural
gas for the year ended December 31, 1996 compared with $17.16 per Bbl of crude
oil, $10.83 per Bbl of natural gas liquid and $1.47 per MMcf of natural gas for
the year ended December 31, 1995. A general strengthening of crude oil and
natural gas prices at the wellhead during 1996 resulted in a higher average
sales prices received by the Company during the year ended December 31, 1996
compared to the same period in 1995.

Lease Operating Expenses. Lease operating expenses and natural gas
processing costs ("LOE"), increased by 41.2% from $4.3 million for the year
ended December 31, 1995 to $6.1 million for the same period of 1996, primarily
due to the greater number of wells owned by the Company for the year ended
December 31, 1996 compared to the year ended December 31, 1995. The Company's
LOE on a per BOE basis for 1996 was $3.28 per BOE as compared to $3.81 per BOE
in 1995.

G & A Expenses. General and administrative expenses increased 85.5%
from $1.0 million for the year ended December 31, 1995, to $1.9 million for the
year ended December 31, 1996, as a result of the Company's hiring additional
staff, including establishment of a Canadian administrative office, to manage
the additional properties acquired by the Company and subsequent development of
those properties. The Company's G & A expense on a per BOE basis was $1.08 per
BOE in 1996 compared to $0.92 per BOE for 1995.

DD & A Expenses. Due to the increase in sales volumes of crude oil
and natural gas, depreciation, depletion and amortization expense increased
76.8% from $5.4 million for the year ended December 31, 1995 to $9.6 million for
the year ended December 31, 1996. The Company's DD&A expense on a per BOE basis
for 1996 was $5.38 per BOE as compared to $4.78 per BOE in 1995.

Interest Expense and Preferred Dividends. Interest expense and
preferred dividends increased 54.5%, from $4.3 million to $6.6 million for the
year end December 31, 1996, compared to the 1995 period. This increase is
attributable to increased borrowings by the Company to finance the acquisitions
consumated during 1996. Long-term debt increased from $41.6 million at December
31, 1995 to $215.0 million at December 31, 1996.

Comparison of Year Ended December 31, 1995 to Year Ended December 31, 1994

Operating Revenue. During the year ended December 31, 1995, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
22.9% from $11.1 million in 1994 to $13.7 million. This increase was primarily
attributable to an increase in crude oil and natural gas liquids sales volumes
of 16% and natural gas sales volumes of 48%. The increases in sales volumes of
crude oil, natural gas liquids and natural gas from 1994 to 1995 were primarily
a result of the acquisition of 80% of the overriding royalty interest previously
granted to a lender (the "ORRI") and the West Texas Properties by the Company in
June 1994 and July 1994 respectively, and the Company's ongoing development
drilling program. Average sales prices were $17.16 per Bbl of crude oil, $10.83
per Bbl of natural gas liquids and $1.47 per Mcf of natural gas for the year
ended December 31, 1995 compared with $15.47 per Bbl of crude oil, $10.54 per

<PAGE>

Bbl of natural gas liquid and $1.85 per Mcf of natural gas for the year ended
December 31, 1994. A general weakening of natural gas prices at the wellhead
during the first nine months of 1995 resulted in a lower average natural gas
sales price received by the Company during the year ended December 31, 1995
compared to the same period in 1994. This decrease was partially offset by an
increase in crude oil prices received by the Company in 1995 as compared to
1994.

Lease Operating Expenses. LOE increased 17.3% from $3.7 million for
the year ended December 31, 1994 to $4.3 million for the same period of 1995,
primarily due to the greater number of wells owned by the Company during the
year ended December 31, 1995 compared to the year ended December 31, 1994. The
Company's LOE on a per BOE basis for the year ended December 31, 1994 was $4.26
per BOE as compared to $3.81 per BOE for the year ended December 31, 1995.

G & A Expenses. G & A expenses increased by 28.6%, from $810,000 to
$1.0 million, from the year ended December 31, 1994 to the year ended December
31, 1995 as a result of hiring additional staff to manage and develop the West
Texas Properties. The Company's G & A expenses on a per BOE basis for the year
ended December 31, 1994 were $0.93 per BOE as compared to $0.92 per BOE for the
year ended December 31, 1995.

DD & A Expenses. Due to the increase in sales volumes of crude oil
and natural gas, depreciation, depletion and amortization expense increased
43.4% from $3.8 million for the year ended December 31, 1994 to $5.4 million for
the year ended December 31, 1995. The Company's DD&A expenses on a per BOE basis
for the year ended December 31, 1994 was $4.37 per BOE compared to $4.78 per BOE
in 1995.

Interest Expenses and Preferred Dividends. As a result of the
Company's borrowing $28 million to acquire the West Texas Properties in July
1994, interest expense increased 62.5% from $2.4 million in 1994 to $3.9 million
in 1995. Long term debt increased from $41.3 million at December 31, 1994 to
$41.6 million at December 31, 1995.

The Company has incurred operating losses and net losses for a number
of years. The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for crude oil and natural gas and
the volumes of crude oil, natural gas and natural gas liquids produced by the
Company. Natural gas prices increased substantially during 1996. For the year
ended December 31, 1996 average natural gas prices realized by the Company were
$1.97 per Mcf compared with $1.47 per Mcf at December 31, 1995 and $1.85 per Mcf
at December 31, 1994. Although the Company had operating and net income during
1996, there can be no assurance that operating income and net earnings will be
achieved in future periods. At December 31, 1996, U.S. crude oil prices were
$23.55 per Bbl compared to $18.13 at December 31, 1995 and $15.59 per Bbl at
December 31, 1994. In addition, because the Company's proved reserves will
decline as crude oil, natural gas and natural gas liquids are produced, unless
the Company is successful in acquiring properties containing proved reserves or
conducts successful exploration and development activities, the Company's
reserves and production will decrease. In the event natural gas prices return to
depressed levels or if crude oil prices begin to decrease, or if the Company's
production levels decrease, the Company's revenues, cash flow from operations
and profitability will be materially adversely affected.

<PAGE>

Liquidity and Capital Resources

Capital expenditures in 1994, 1995 and 1996 were $40.9 million, $9.7
million and $172.9 million, respectively. The table below sets forth the
components of these capital expenditures on a historical basis for the three
years ended December 31, 1994, 1995 and 1996.

Year Ended December 31
------------------------------------
(In thousands)
1996 1995 1994
--------- --------- --------
Expenditure category:
Property acquisition (1) $154,484 $ 719 $33,709
(Divestitures) (242) (2,556) (70)
Development 18,465 11,472 7,151
Facilities and other 206 139 158
-------- ------- -------
Total $172,913 $ 9,774 $40,948
======== ======= =======

(1) Acquisition costs includes 45,741 shares of Preferred Stock valued at
$4.6 million in 1994.

Acquisitions of crude oil and natural gas producing properties
beginning during 1991 and continuing through the year ended December 31, 1996
account for the majority of the capital expenditures made by the Company since
January 1, 1991. These expenditures were funded through internally generated
cash flow, borrowings from the Company's previous lenders and the Banks, the
issuance of shares of the Company's Common and Preferred Stock to property
sellers and the issuance of the Senior Notes.

At December 31, 1996, the Company had current assets of $23.3 million
and current liabilities of $16.9 million resulting in working capital of $6.4
million. This compares to working capital of $2.6 million at December 31, 1995.
The material components of the Company's current liabilities at December 31,
1996 include trade accounts payable of $10.0 million, revenues due third parties
of $2.4 million and accrued interest of $3.2 million. Shareholders' equity
decreased from $37.1 million at December 31, 1995 to $35.7 million at December
31, 1996 primarily due to an unrealized foreign currency translation adjustment
of $2.4 million.

The Company's current budget for capital expenditures for 1997 other
than acquisition expenditures is $35.2 million. Such expenditures will be made
primarily for the development of existing properties. Additional capital
expenditures may be made for acquisition of producing properties if such
opportunities arise, but the Company currently has no agreements, arrangements
or undertakings regarding any material acquisitions. The Company has no material
long-term capital commitments and is consequently able to adjust the level of
its expenditures as circumstances dictate. Additionally, the level of capital
expenditures will vary during future periods depending on market conditions and
other related economic factors.

On November 14, 1996, Abraxas and Canadian Abraxas consummated the
offering of $215 million of the Notes. Interest on the Notes accrues from their
date of original issuance (the "Issue Date") and is payable semi-annually in
arrears on May 1 and November 1 of each year, commencing on May 1, 1997, at the
rate of 11.5% per annum. The Notes are redeemable, in whole or in part, at the
option of Abraxas and Canadian Abraxas, on or after November 1, 2000, at the
redemption prices set forth below, plus accrued and unpaid interest to the date
of redemption, if redeemed during the 12-month period commencing on November 1
of the years set forth below:

Year Percentage
---- ----------
2000 105.75%
2001 102.875%
2002 and thereafter 100%

In addition, at any time on or prior to November 1, 1999, Abraxas and
Canadian Abraxas may, at their option, redeem up to 35% of the aggregate
principal amount of the Notes originally issued with the net cash proceeds of
one or more equity offerings, at a redemption price equal to 111.5% of the
aggregate principal amount of the Notes to be redeemed, plus accrued and unpaid
interest to the date of redemption; provided, however, that after giving effect
to any such redemption, at least $139.75 million aggregate principal amount of
the Notes remains outstanding.

<PAGE>

The Notes are joint and several obligations of Abraxas and Canadian
Abraxas, and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Notes rank
senior in right of payment to all future subordinated indebtedness of Abraxas
and Canadian Abraxas. The Notes are, however, effectively subordinated to
secured indebtedness of Abraxas and Canadian Abraxas to the extent of the value
of the assets securing such indebtedness.

The Notes are unconditionally guaranteed, jointly and severally, by
certain of Abraxas' and Canadian Abraxas' future subsidiaries (the "Subsidiary
Guarantors"). The guarantees are general unsecured obligations of the Subsidiary
Guarantors and rank pari passu in right of payment to all unsubordinated
indebtedness of the Subsidiary Guarantors and senior in right of payment to all
subordinated indebtedness of the Subsidiary Guarantors. The Guarantees are
effectively subordinated to secured indebtedness of the Subsidiary Guarantors to
the extent of the value of the assets securing such indebtedness. As of December
31, 1996, Abraxas, Canadian Abraxas and the Subsidiary Guarantors had no secured
indebtedness outstanding.

Upon a Change of Control (as defined in the Indenture governing the
Notes), each holder of the Notes will have the right to require Abraxas and
Canadian Abraxas to repurchase all or a portion of such holder's Notes at a
redemption price equal to 101% of the principal amount thereof, plus accrued and
unpaid interest to the date of repurchase. In addition, Abraxas and Canadian
Abraxas will be obligated to offer to repurchase the Notes at 100% of the
principal amount thereof plus accrued and unpaid interest to the date of
repurchase in the event of certain asset sales.

The net proceeds to Abraxas and Canadian Abraxas from the offering of
the Notes were approximately $207.0 million after deducting underwriting
discounts and estimated offering expenses payable by Abraxas and Canadian
Abraxas. Abraxas and Canadian Abraxas used the net proceeds to (i) repay all
amounts outstanding under its bridge facility dated September 30, 1996 with
Bankers Trust Company ("BT") and other lenders in the amount of $85.0 million,
(ii) acquire the outstanding capital stock of CGGS for $94.7 million, (iii)
acquire the Portilla and Happy properties and repay certain indebtedness for
$27.5 million and (iv) provide working capital for general corporate purposes
including future acquisitions and development of producing properties.

After consummation of the Offering and application of the net proceeds
therefrom, the Company increased its total outstanding debt to approximately
$215.1 million. In addition, on November 14, 1996, the Company entered into the
Credit Facility concurrently with the consummation of the Offering. The Credit
Facility provides for a revolving line of credit with an initial availability of
$20.0 million, subject to certain customary conditions including a borrowing
base condition.

Commitments available under the Credit Facility are subject to borrowing
base redeterminations to be performed semi-annually and, at the option of each
of the Company and the Banks, one additional time per year. Any outstanding
principal balance in excess of the borrowing base will be due and payable in
three equal monthly payments after a borrowing base redetermination. The
borrowing base will be determined in BT's sole discretion, subject to the
approval of the Banks, based on the value of the Company's reserves as set forth
in the reserve report of the Company's independent petroleum engineers, with
consideration given to other assets and liabilities.

The Credit Facility has an initial revolving term of two years and a
reducing period of three years from the end of the initial two-year period. The
commitment under the Credit Facility will be reduced during such reducing period
by eleven equal quarterly reductions. Quarterly reductions will equal 8.2% per
quarter with the remainder due at the end of the three-year reducing period.

<PAGE>

available borrowing base, then the applicable interest rate on the outstanding
principal will be either (a) LIBOR plus 1.75% or (b) the prime rate of BT plus
0.50%. If the borrowings under the Credit Facility represent an amount greater
than or equal to 66.7% of the available borrowing base, then the applicable
interest rate on the outstanding principal will be either (a) LIBOR plus 2.00%
or (b) the prime rate of BT plus 0.50%. LIBOR elections can be made for periods
of one, three or six months.

The Credit Facility contains customary events of default, including
nonpayment of principal, interest or fees, violation 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 and change of control. The Indenture also contains a number of
covenants and events of default including covenants restricting, among other
things, the Company's ability to incur additional indebtedness, incur liens, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, merge or consolidate
with any other person or sell, assign, transfer, lease, convey or otherwise
dispose of all or substantially all of the assets of the Company and events of
default including nonpayment of principal or interest on the Notes, violation of
covenants, cross default on other indebtedness, bankruptcy and material
judgments.

The Indenture also provides that the Company may not, and may not cause
or permit certain of its subsidiaries, including Canadian Abraxas, to, directly
or indirectly, create or otherwise cause to permit to exist or become effective
any encumbrance or restriction on the ability of such subsidiary to pay
dividends or make distributions on or in respect of its capital stock, make
loans or advances or pay debts owed to Abraxas, guarantee any indebtedness of
Abraxas or transfer any of its assets to Abraxas except for such encumbrances or
restrictions existing under or by reason of: (I) applicable law; (ii) the
Indenture; (iii) the Credit Facility; (iv) customary non-assignment provisions
of any contract or any lease governing leasehold interests of such subsidiaries;
(v) any instrument governing indebtedness assumed by the Company in an
acquisition, which encumbrance or restriction is not applicable to such
subsidiaries or the properties or assets of such subsidiaries other than the
entity or the properties or assets of the entity so acquired; (vi) customary
restrictions with respect to subsidiaries of the Company pursuant to an
agreement that has been entered in to for the sale or disposition of capital
stock or assets of such subsidiaries 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; (vii) any instrument governing certain liens permitted by
the Indenture, to the extent and only to the extent such instrument restricts
the transfer or other disposition of assets subject to such lien; or (viii) an
agreement governing indebtedness incurred to refinance the indebtedness issued,
assumed or incurred pursuant to an agreement referred to in clause (ii), (iii)
or (v) 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 of the Notes in any material respect as determined
by the Board of Directors of the Company in their reasonable and good faith
judgement than the provisions relating to such encumbrance or restriction
contained in the applicable agreement referred to in such clause (ii), (iii) or
(v).

In August 1995, the Company entered into a rate swap agreement with a
previous lender relating to $25.0 million of principal amount of outstanding
indebtedness. This agreement was assumed by the Banks in connection with a
bridge facility that was subsequently paid off. Under the agreement, the Company
pays a fixed rate of 6.15% while the Banks in l pay a floating rate equal to the
USD-LIBOR-BBA rate for one month maturities, quoted on the eighteenth day of
each month, to the Company. Settlements are due monthly. The agreement
terminates in August 1998. At December 31, 1996, the fair value of this swap, as
determined by BT CO was approximately $200,000 and was recorded as interest
expense at December 31, 1996.

<PAGE>

In connection with the re-acquisition of the Portilla and Happy Fields,
the Company assumed a commodity price hedge on variable volumes of crude oil and
natural gas. Monthly settlements with amounts either due to or from Christiania
are based on the differential between a fixed and a variable price for crude oil
and natural gas. During 1997, the approximate monthly volume of crude oil sales
subject to this agreement is 15,800 barrels at a fixed price of $17.20. This
agreement reduces to approximately 13,200 barrels per month in 1998, 11,000
barrels per month in 1999, 9,100 barrels per month in 2000 and 8,200 barrels per
month in 2001 until November 1. The fixed price paid to the Company over this
five year period averages $17.55 per barrel. The natural gas component of this
agreement calls for approximately 54,000 MMBTU per month at a fixed price of
$1.80 during 1997 with volumes decreasing to 37,000 MMBTU per month in 1998,
24,000 MMBTU per month in 1999, 19,000 MMBTU per month in 2000 and 15,000 MMBTU
per month in 2001 through October. The fixed price paid to the Company over this
five year period averages $1.84 per MMBTU.

The Company has also entered into two fixed price agreements, each
relating to approximately 3,750 net Mcf per day of natural gas. The first of
these two expires on March 31, 1997 and calls for a fixed price of $1.52 per
MMBTU being paid to the Company. The second agreement expires on October 31,
1997 and provides a fixed price of $1.42 per MMBTU to the Company.

The Company has also recently entered into a costless collar relating to
1,000 barrels a day of oil sales for the period February 1, 1997 through
December 31, 1997. This agreement guarantees a minimum price of $19.00 per
barrel to the Company and provides that any amount above $25.60 per barrel be
remitted by the Company to the counterparty to the agreement.

Operating activities for the year ended December 31, 1996 provided $13.5
million of cash to the Company. Investing activities required $172.6 million
during 1996 primarily for the acquisition of the Wyoming Properties, CGGS and
the Portilla and Happy Fields. Financing provided $163.0 million during 1996.

For the year ended December 31, 1995, operating activities provided $4.5
million of cash. Investing activities required $10.1 million primarily for the
development of existing properties. Total cash provided from financing
activities for 1995 was $9.8 million as the result of the sale of 1,330,000
shares of Common Stock and contingent value rights during November 1995 which
resulted in net proceeds of $10.1 million.

During 1994, operating activities provided $4.4 million of cash.
Investing activities during 1994 utilized $36.0 million of cash primarily for
the acquisition of the ORRI and the West Texas Properties for $29.0 million and
the development of producing properties of $7.2 million. The Company borrowed
$40.9 million during 1994, repaid $12.7 million of long term debt, sold Common
Stock for proceeds of $1.5 million and paid financing fees and dividends on
preferred stock resulting in a net contribution of $29.2 million from financing
activities.

The Company is heavily dependent on crude oil and natural gas prices
which have historically been volatile. Although the Company has hedged a portion
of its natural gas production and intends to continue this practice, future
crude oil and natural gas price declines would have a negative impact on the
Company's overall results, and therefore, its liquidity. Furthermore, low crude
oil and natural gas prices could affect the Company's ability to raise capital
on terms favorable to the Company.

At December 31, 1996, the Company had, subject to the limitations
discussed below, $20.1 million of net operating loss carryforwards for U.S. tax
purposes, of which approximately $17.5 million are available for utilization
without limitation. These loss carryforwards will expire from 2002 through 2010
if not utilized. At December 31, 1996, the company had approximately $830,000 of
net operating loss carryforwards for Canadian tax purposes which expire in 2003.
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 of the Internal Revenue Code of 1986, as amended (Section 382), occurred in
December 1991. Accordingly, it is expected that the use of net operating loss
carryforwards generated prior to December 31, 1991 of $4.9 million will be
limited to approximately $235, 000 per year. As a result of the issuance of
additional shares of Common Stock for acquisitions and sales of 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 or $8.2 million will be limited to
approximately $1 million per year subject to the lower limitations described
above. Of the $8.2 million net operating loss carryforwards, it is anticipated
that the maximum net operating loss that may be utilized before it expires is

<PAGE>

$7.2 million. Future changes in ownership may further limit the use of the
Company's carryforwards. 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 $5.7 million and
$5.7 million for deferred tax assets at December 31, 1996 and 1995,
respectively.

Based upon the current level of operations, the Company believes that
cash flow from operations and the Company's Credit Facility with The Banks, will
be adequate to meet its anticipated requirements for working capital, capital
expenditures and scheduled interest payments through 1997. A depressed price for
natural gas or crude oil will have a material adverse effect on the Company's
cash flow from operations and anticipated levels of working capital, and could
force the Company to revise its planned capital expenditures.

Disclosure Regarding Forward-Looking Information

This report includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements other than statements of historical facts included in this report
regarding the Company's financial position, business strategy, budgets, reserve
estimates, development and exploitation opportunities and projects, behind pipe
zones, classification of reserves, projected costs, potential reserves, and
plans and objectives of management for future operations including, but not
limited to, statements including, any of the terms "anticipates", "expects",
"estimates", "believes" and similar terms are forward-looking statements.
Although the Company believes that the expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from the Company's expectations ("Cautionary
Statements") are disclosed under "Risk Factors" and elsewhere in this report
including, without limitation, in conjunction with the forward-looking
statements included in this report. All subsequent written and oral
forward-looking statements attributable to the Company, or persons acting on its
behalf, are expressed qualified in their entirety by the Cautionary Statements.

Item 8. Financial Statements.

For the financial statements and supplementary data required by this
Item 8, see the Index to Consolidated Financial Statements and Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.

Not Applicable.

PART III

Item 10. Directors and Executive Officers of the Registrant.

There is incorporated in this Item 10 by reference that portion of
the Company's definitive proxy statement for the 199 annual meeting of
shareholders which appears therein under the caption "Election of Directors".
See also the information in Item 4a of Part I of this Report.

Item 11. Executive Compensation.

There is incorporated in this Item 11 by reference that portion of
the Company's definitive proxy statement for the 1997 annual meeting of
shareholders which appears therein under the caption "Executive Compensation",
except for those parts under the captions "Compensation Committee Report on
Executive Compensation", "Report on Repricing Options" and "Performance Graph".

<PAGE>

Item 12. Security Ownership of Certain Beneficial Owners and Management.

There is incorporated in this Item 12 by reference that portion of
the Company's definitive proxy statement for the 1997 annual meeting of
shareholders which appears therein under the caption "Securities Holdings of
Principal Shareholders, Directors and Officers".

Item 13. Certain Relationships and Related Transactions.

There is incorporated in this Item 13 by reference that portion of
the Company's definitive proxy statement for the 1997 Annual Meeting of
Shareholders which appears therein under the caption "Certain Transactions."

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)1. Consolidated Financial Statements Page

Report of Ernst & Young, LLP, Independent Auditors.............F-2

Consolidated Balance Sheets,
December 31, 1996 and 1995...................................F-3

Consolidated Statements of Operations,
Years Ended December 31, 1996, 1995, and 1994................F-5

Consolidated Statements of Shareholders' Equity
Years ended December 31, 1996, 1995 and 1994................F-7

Consolidated Statements of Cash Flows
Years Ended December 31, 1996, 1995 and 1994.................F-8

Notes to Consolidated Financial Statements.....................F-10

(a)2. Financial Statement Schedules

All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.

<PAGE>

Item 14 (b): Reports on Form 8-K Filed in the Fourth Quarter of 1996:

Form 8-K dated October 15. 1996 and amended on December 15, 1996

Item 2. Acquisition or Disposition of Assets - acquisition
of Enserch Properties.

Item 7. Financial Statements and Exhibits - financial
statements of Enserch Properties

Form 8-K dated November 7, 1996

Item 5. Other Events - pricing of Senior Notes placement

Form 8-K dated November 27, 1996 and amended on January 27, 1997

Item 2. Acquisition or Disposition of Assets - acquisition
of Canadian Gas Gathering Systems, Inc. Acquisition of
Portilla - 1996 L.P. Limited Partnership interest.

Item 5. Other Events - Senior Notes Offering, CVR maturity
extension

Item 7. Financial Statements and Exhibits - Financial
statements of CGGS and Portilla-1996 L.P.

<PAGE>

(a)3. Exhibits

The following Exhibits have previously been filed by the Registrant
or are included following the Index to Exhibits.

Exhibit Number. Description

3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to the Company's
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).

3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990 (Filed as Exhibit 3.3 to the S-4 Registration Statement). 3.3
Articles of Amendment to the Articles of Incorporation of Abraxas dated December
18, 1990.
(Filed as Exhibit 3.4 to the S-4 Registration Statement).

3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June
8, 1995. (Filed as Exhibit 3.4 to the Company's Registration Statement on Form
S-3, No. 333-398 (the "S-3 Registration Statement")).

3.5 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.5 to the S-3
Registration Statement).

3.6 Certificate of Designation of Series 1995-B Preferred Stock of Abraxas.
(Filed as Exhibit 3.6 to the S-3 Registration Statement).

3.7 Articles of Incorporation of Canadian Abraxas. (Filed as Exhibit 3.7 to the
Company's and Canadian Abraxas' Registration Statement on Form S-4, No.
333-18673 (the "Exchange Offer Registration Statement")).

3.8 By-Laws of Canadian Abraxas. (Filed as Exhibit 3.8 to the Exchange Offer
Registration Statement).

4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the
S-4 Registration Statement).

4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to
the Company's Annual Report on Form 10-K filed on March 31, 1995).

4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First
Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1 to the
Company's Registration Statement on Form 8-A filed on December 6, 1994).

4.4 Contingent Value Rights Agreement dated November 17, 1995 by and between the
Company and FUNB (Filed as Exhibit 4.1 to the Company's Current Report on Form
8-K dated November 21, 1995).

4.5 First Amendment to Contingent Value Rights Agreement dated May 2, 1996 by
and between the Company and FUNB. (Filed as Exhibit 4.5 to the S-3 Registration
Statement).

4.6 Indenture dated November 14, 1996 by and among the Company, Canadian Abraxas
and IBJ Schroder Bank and Trust Company. (Filed as Exhibit 4.1 to the Company's
Current Report on Form 8-K dated November 27, 1996).

4.7 Form of Note. (Filed as Exhibit 4.7 to the Exchange Offer Registration
Statement).

4.8 Specimen Common Stock Certificate of Canadian Abraxas. (Filed as Exhibit 4.8
to the Exchange Offer Registration Statement).

<PAGE>

*10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.7 to the Company's 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 the Company's 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 the Company's 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 the Exchange Offer Registration Statement).

*10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the Exchange Offer Registration Statement).

*10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors. (Filed
as Exhibit 10.20 to the Company's 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 the Company's 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 the Company's Annual Report on Form 10-K filed on April 12,
1994).

10.9 Registration Rights and Stock Registration Agreement dated as of August 11,
1993 by and among Abraxas, EEP and Endowment Energy Partners II, Limited
Partnership ("EEP II"). (Filed as Exhibit 10.33 to the Company's Registration
Statement on Form S-1, Registration No. 33-66446 (the "S- 1 Registration
Statement")).

10.10 First Amendment to Registration Rights and Stock Registration Agreement
dated June 30, 1994 by and among Abraxas, EEP and EEP II. (Filed as Exhibit 10.3
to the Registrant's Current Report on Form 8-K filed on July 14, 1994).

10.11 Second Amendment to Registration Rights and Stock Registration Agreement
dated September 2, 1994 by and among Abraxas, EEP and EEP II. (Filed as Exhibit
10.3 to the Company's Annual Report on Form 10-K filed March 31, 1995)

10.12 Third Amendment to Registration Rights and Stock Registration Agreement
dated November 17, 1995 by and among Abraxas, EEP and EEP II. (Filed as Exhibit
10.17 to the Company's Annual Report on Form 10-K filed March 31, 1995)

10.13 Common Stock Purchase Warrant dated as of December 18, 1991 between
Abraxas and EEP. (Filed as Exhibit 12.3 to the Company's Current Report on Form
8-K filed January 9, 1992).

10.14 Common Stock Purchase Warrant dated as of August 1, 1993 between Abraxas
and EEP. (Filed as Exhibit 10.35 to the S-1 Registration Statement).

10.15 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and
EEP II. (Filed as Exhibit 10.36 to the S-1 Registration Statement).

10.16 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and
Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to the S-1 Registration
Statement).

10.17 Letter dated September 2, 1994 from Abraxas to EEP and EEP II. (Filed as
Exhibit 10.13 to the Company's Annual Report on Form 10-K filed March 31, 1995)

<PAGE>

10.18 Amended and Restated Credit Agreement dated as of November 14, 1996 among
Abraxas, Bankers Trust Company, Inc. (U.S.) Capital Corporation and the Lenders
named therein. (Filed as Exhibit 10.5 to the Company's Current Report on Form
8-K filed November 27, 1996).

10.19 Warrant Agreement dated as of July 27, 1994 between Abraxas and FUNB.
(Filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed August
5, 1994).

10.20 Warrant Agreement dated as of December 16, 1994, between Abraxas and FUNB.
(Filed as Exhibit 10.23 to the Company's Annual Report on Form 10-K filed March
31, 1995).

10.21 First Amendment to Warrant Agreement dated as of August 31, 1995 between
Abraxas and FUNB. (Filed as Exhibit 10.21 to the S-3 Registration Statement).

10.22 Form of Indemnity Agreement between Abraxas and each of its directors and
officers. (Filed as Exhibit 10.30 to the S-1 Registration Statement).

*10.23 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as
Exhibit 10.23 to the S-3 Registration Statement).

*10.24 Employment Agreement between Abraxas and Chris E. Williford. (Filed as
Exhibit 10.24 to the S-3 Registration Statement).

*10.25 Employment Agreement between Abraxas and Robert Patterson. (Filed as
Exhibit 10.25 to the S-3 Registration Statement).

*10.26 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as
Exhibit 10.26 to the S-3 Registration Statement).

10.27 Common Stock and Contingent Value Rights Purchase Agreement dated as of
November 17, 1995 by and among Abraxas and the Purchasers named in Schedule l
thereto. (Filed as Exhibit 10.1 to the Company's Current Report on Form 8-K
dated November 21, 1995.)

10.28 Registration Agreement dated November 17, 1995 by and among the Company
and the parties named in Schedule I thereto. (Filed as Exhibit 10.2 to the
Company's Current Report on Form 8-K dated November 21, 1995.)

10.29 Subscription Agreement between Registrant and Grey Wolf Exploration, Ltd.
(Filed as Exhibit 10.1 to the Company's Current Report on Form 8-K dated January
17, 1995.)

10.30 Subscription Agreement between Grey Wolf Exploration, Ltd. and Cascade Oil
and Gas Ltd. (Filed as Exhibit 10.2 to the Company's Current Report on Form 8-K
dated January 17, 1995.)

10.31 Purchase Agreement dated November 14, 1996 by and among Abraxas, Canadian
Abraxas, BT Securities Corporation, Jefferies & Company, Inc. and ING Baring
(U.S.) Securities Corporation (collectively, the "Initial Purchasers"). (Filed
as Exhibit 10.1 to the Company's Current Report on Form 8-K filed November 27,
1996).

10.32 Registration Rights Agreement dated November 14, 1996 by and among
Abraxas, Canadian Abraxas, and the Initial Purchasers. (Filed as Exhibit 10.2 to
the Company's Current Report on Form 8- K filed November 27, 1996).

10.33 Share Sale Agreement dated October 29, 1996 by and among Abraxas, Canadian
Abraxas, CGGS Canadian Gas Gathering Systems Inc. ("CGGS") and the shareholders
of CGGS. (Filed as Exhibit 10.3 to the Company's Current Report on Form 8-K
filed November 27, 1996).

<PAGE>

10.34 Purchase and Sale Agreement dated September 18, 1996 by and among Abraxas,
Acco, LLC, Massachusetts Bay Transportation Authority Retirement Fund,
Metropolitan Life Insurance Company Separate Account No. 175, The General Mills,
Inc. Master Trust: Pooled Real Estate Fund and State Street Research Energy,
Inc. (Filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed
November 27, 1996).

10.35 Purchase and Sale Agreement dated May 22, 1996 between Abraxas and Enserch
Exploration, Inc. (Filed as Exhibit 10.1 to the Company's Current Report on Form
8-K filed October 15, 1996).

10.36 Management Agreement dated November 14, 1996 by and between Canadian
Abraxas and Cascade Oil & Gas Ltd. (Filed as Exhibit 10.36 to the Exchange Offer
Registration Statement).

11.1 Earnings per share Computation Statement

18.1 Letter regarding change in accounting principle. (Filed as Exhibit 18.1 to
the Registrant's Annual Report on Form 10-K filed on April 12, 1994).

22.1 Subsidiaries of Abraxas. (Filed as Exhibit 22.1 to the Exchange Offer
Registration Statement).

23.1 Consent of Independent Auditors. (Filed as Exhibit 23.1 to The Registrant's
Annual Report on Form 10-K filed March 31, 1997).

23.2 Consent of independent, third party, Petroleum Engineers. (Filed as Exhibit
23.2 to The Registrant's Annual Report on Form 10-K filed March 31, 1997).

27.1 Financial Data Schedule.

* Management Compensatory Plan or Agreement.

<PAGE>
INDEX TO FINANCIAL STATEMENTS
Page

Abraxas Petroleum Corporation and Subsidiaries

Report of Independent Auditors ..........................................F-2
Consolidated Balance Sheets at December 31, 1995 and 1996 ...............F-3
Consolidated Statements of Operations for the years ended
December 31, 1994, 1995, and 1996 ....................................F-5
Consolidated Statements of Shareholders' Equity for the years
ended December 31, 1994, 1995, and 1996 ..............................F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 1994,1995, and 1996 .....................................F-8
Notes to Consolidated Financial Statements ..............................F-10

F-1
<PAGE>

Report of Independent Auditors

The Board of Directors and Shareholders
Abraxas Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and Subsidiaries as of December 31, 1995 and 1996, and the
related consolidated statements of operations, shareholders' equity, and cash
flows for each of the three years in the period ended December 31, 1996. 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 generally accepted auditing
standards. 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, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Abraxas
Petroleum Corporation and Subsidiaries at December 31, 1995 and 1996, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.

ERNST & YOUNG LLP

San Antonio, Texas
March 21, 1997

F-2
<PAGE>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31
--------------------
1995 1996
--------- --------
(In thousands)

Current assets:
Cash .................................................. $ 4,250 $ 8,290
Accounts receivable, less allowance
for doubtful accounts:
Joint owners ...................................... 1,335 1,601
Oil and gas production sales ...................... 2,946 11,400
Affiliates, officers, and shareholders ............ 53 94
Other ............................................. 60 1,289
-------- --------
4,394 14,384

Equipment inventory ................................... 80 451
Other current assets .................................. 125 187
-------- --------
Total current assets ................................ 8,849 23,312

Property and equipment ................................... 104,997 310,043
Less accumulated depreciation, depletion,
and amortization ....................................... 29,919 38,653
-------- --------
Net property and equipment based on the full cost
method of accounting for oil and gas properties
of which $-0- and $37,268 at December 31, 1995 and
1996, respectively, were excluded from amortization . 75,078 271,390
Deferred financing fees, net of accumulated amortization
of $289 and $280 at December 31, 1995 and 1996,
respectively .......................................... 354 9,335
Restricted cash .......................................... 134 90
Marketable securities .................................... 326 --
Other assets ............................................. 326 715
======== ========
Total assets .......................................... $ 85,067 $304,842
======== ========

See accompanying notes.

F-3

<PAGE>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (CONTINUED)

LIABILITIES AND SHAREHOLDERS' EQUITY

December 31
--------------------
1995 1996
--------- --------
(In thousands)
Current liabilities:
Accounts payable and other accrued liabilities ..... $ 3,929 $ 9,960
Oil and gas production payable ..................... 1,787 2,378
Accrued interest ................................... 363 3,206
Income taxes payable ............................... -- 145
Other accrued expenses ............................. 46 1,132
Dividends payable on preferred stock ............... 91 --
Payable to affiliates .............................. -- 58
--------- ---------

Total current liabilities ........................ 6,216 16,879

Long-term debt:
Senior notes ....................................... -- 215,000
Financing agreements ............................... 41,557 --
Other .............................................. 44 32
--------- ---------

41,601 215,032

Other long-term obligations ........................... -- 87
Deferred income taxes ................................. 187 32,928
Minority interest in foreign subsidiary ............... -- 2,157
Future site restoration ............................... -- 2,103

Commitments and contingencies

Shareholders' equity:
Preferred stock 8%, authorized 1,000,000 shares;
issued and outstanding 45,741 shares
at December 31, 1995 and 1996 .................... -- --
Common stock, par value $.01 per share - authorized
50,000,000 shares; issued 5,799,762 and 5,806,812
shares at December 31, 1995 and 1996, respectively 58 58
Additional paid-in capital ......................... 50,914 50,926
Unrealized holding loss on securities .............. (244) --
Accumulated deficit ................................ (13,664) (12,517)
Treasury stock, at cost, 2,571, and 74,711 shares
at December 31, 1995 and 1996, respective......... (1) (405)
Foreign currency translation adjustment ............ -- (2,406)

--------- ---------
Total shareholders' equity ............................ 37,063 35,656
--------- ---------
Total liabilities and shareholders' equity ...... $ 85,067 $ 304,842
========= =========

See accompanying notes.

F-4
<PAGE>
<TABLE>
<CAPTION>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Year Ended December 31
------------------------------------
1994 1995 1996
---------- --------- ---------
(In thousands except shares
and per share data)
Revenue:
<S> <C> <C> <C>
Oil and gas production revenues ........ $ 11,114 $ 13,660 $ 25,749
Gas processing revenues ................ -- -- 600
Rig revenues ........................... 161 108 139
Other .................................. 74 49 165
---------- --------- ---------

11,349 13,817 26,653

Operating costs and expenses:
Lease operating and production taxes ... 3,693 4,333 5,858
Gas processing costs ................... -- -- 262
Depreciation, depletion, and
amortization ......................... 3,790 5,434 9,605
Rig operations ......................... 133 125 169
General and administrative ............. 810 1,042 1,933
---------- --------- ---------
8,426 10,934 17,827
---------- --------- ---------
Operating income .......................... 2,923 2,883 8,826

Other (income) expense:
Interest income ........................ (16) (34) (254)
Amortization of deferred financing fee . 400 214 280
Interest expense ....................... 2,359 3,911 6,241
Loss on marketable securities .......... -- -- 235
Other expense .......................... 67 -- 138

---------- --------- ---------
2,810 4,091 6,640
---------- --------- ---------
Income (loss) from continuing operations
before taxes and extraordinary items ... 113 (1,208) 2,186
Income tax expense (benefit):
Current ................................ -- -- 176
Deferred ............................... -- -- --
Minority interest in income of consolidated
foreign subsidiary ..................... -- -- 70
---------- --------- ---------
Income (loss) from continuing operations
before extraordinary items ............. 113 (1,208) 1,940

</TABLE>

F-5
<PAGE>
<TABLE>
<CAPTION>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (CONTINUED)

Year Ended December 31
------------------------------------
1994 1995 1996
---------- --------- ---------
(In thousands except shares
and per share data)
<S> <C> <C> <C>
Discontinued operations:
Loss from operations of discontinued
coal properties ................... $ (348) $ -- $ --
Loss on disposal of discontinued coal
properties ........................ (988) -- --
---------- --------- ---------
Loss from discontinued operations ...... (1,336) -- --
---------- --------- ---------
Income (loss) before extraordinary items (1,223) (1,208) 1,940
Extraordinary item:
Debt extinguishment costs ........... (1,172) -- (427)
---------- --------- ---------
Net income (loss) ...................... (2,395) (1,208) 1,513
Less dividend requirement on cumulative
preferred stock ..................... (183) (366) (366)
---------- --------- ---------
Net income (loss) applicable to common
stock ............................... $ (2,578) $ (1,574) $ 1,147
========== ========= =========
Earnings per common and common
equivalent share:
Income (loss) from continuing
operations ...................... $ (.02) $ (.34) $ .23
Discontinued operations ........... (.31) - -
Extraordinary items ............... (.27) - (.06)
---------- --------- ---------
Net income (loss) per share ........ $ (.60) $ (.34) $ .17
========== ========= =========

Weighted average shares outstanding .... 4,309,878 4,635,412 6,794,442
========== ========= =========
</TABLE>

See accompanying notes.

F-6
<PAGE>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In thousands except share amounts)

Preferred Stock Common Stock Treasury Stock
----------------------- ----------------------- ---------------------
Shares Amount Shares Amount Shares Amount
---------- --------- --------- --------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1994 . -- $ -- 4,202,449 $ 42 -- $ --
Issuance of common stock
for compensation ...... -- -- 10,033 -- -- --
Issuance of preferred
stock for acquisition . 45,741 4,573 -- -- -- --
Options and warrants
exercised ............. -- -- 249,408 3 -- --
Changes in unrealized
holding loss on
securities ........... -- -- -- -- -- --
Dividend on preferred
stock ................. -- -- -- -- -- --
Net loss for the year ... -- -- -- -- -- --
------- --------- --------- --------- ------- --------
Balance at December 31, 1994 45,741 4,573 4,461,890 45 -- --

Issuance of common stock
for compensation ...... -- -- 7,872 -- -- --
Issuance of common stock -- -- 1,330,000 13 -- --
Treasury stock
purchased, net ........ -- -- -- -- 2,571 (1)
Changes in preferred
stock par value ....... -- (4,573) -- -- -- --
Dividend on preferred
stock ................. -- -- -- -- -- --
Net loss for the year ... -- -- -- -- -- --
------- --------- --------- --------- ------- --------
Balance at December 31, 1995 45,741 -- 5,799,762 58 2,571 (1)

Issuance of common stock
for compensation ...... -- -- 5,050 -- (2,500) 1
Expenses paid related to
private placement
offering............... -- -- -- -- -- --
Options exercised ....... -- -- 2,000 -- -- --
Treasury stock purchased -- -- -- -- 74,640 (405)
Dividend on preferred
stock ................. -- -- -- -- -- --
Foreign currency
translation adjustment -- -- -- -- -- --
Changes in unrealized
holding loss on
securities ............ -- -- -- -- -- --
Net income for the year . -- -- -- -- -- --
------- --------- --------- --------- ------- --------
Balance at December 31, 1996 45,741 $ -- 5,806,812 $ 58 74,711 $ (405)
======= ========= ========= ========= ======= ========
</TABLE>

See accompanying notes.

F-7
<PAGE>

<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In thousands except share amounts)

Unrealized
Additional Holding Loss Foreign
Paid-In on Accumulated Currency
Capital Securities Deficit Translation Total
--------- ------------ ----------- ------------ ----------
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1994 . $ 34,614 $ -- $ (9,513) $ -- $ 25,143
Issuance of common stock
for compensation ...... 107 -- -- -- 107
Issuance of preferred
stock for acquisition . -- -- -- -- 4,573
Options and warrants .... 1,496 -- -- -- 1,499
exercised
Changes in unrealized
holding loss on ....... -- (244) -- -- (244)
securities
Dividend on preferred ... -- -- (183) -- (183)
stock
Net loss for the year ... -- -- (2,394) -- (2,394)

------- ----------- --------- --------- -------
Balance at December 31, 1994 36,217 (244) (12,090) -- 28,501
Issuance of common stock
for compensation ...... 74 -- -- -- 74
Issuance of common stock 10,050 -- -- -- 10,063
Treasury stock
purchased, net ........ -- -- -- -- (1)
Changes in preferred
stock par value ....... 4,573 -- -- -- --
Dividend on preferred ...
stock ................. -- -- (366) -- (366)
Net loss for the year ... -- -- (1,208) -- (1,208)
-------- ----------- --------- --------- ---------
Balance at December 31, 1995 50,914 (244) (13,664) -- 37,063

Issuance of common stock
for compensation ...... 41 -- -- -- 42
Expenses paid related to
private placement ..... (42) -- -- -- (42)
offering
Options exercised ....... 13 -- -- -- 13
Treasury stock purchased -- -- -- -- (405)
Dividend on preferred
stock ................ -- -- (366) -- (366)
Foreign currency
translation adjustment -- -- -- (2,406) (2,406)
Changes in unrealized
holding loss on
securities ........... -- 244 -- -- 244
Net income for the year . -- -- 1,513 -- 1,513

-------- ----------- --------- --------- ---------
Balance at December 31, 1996 $ 50,926 $ -- $ (12,517) $ (2,406) $ 35,656
======== =========== ========= ========= =========

See accompanying notes.
</TABLE>
F-7
<PAGE>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31
-----------------------------------
1994 1995 1996
--------- --------- ---------
(In thousands)

Operating Activities
Net income (loss) ....................... $ (2,395) $ (1,208) $ 1,513
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Minority interest in income of
foreign subsidiary ............... -- -- 70
Loss on disposal of discontinued
operations ....................... 987 -- --
Depreciation, depletion, and
amortization ..................... 3,790 5,434 9,605
Amortization of deferred financing
fees ............................. 467 214 280
Issuance of common stock for
compensation ..................... 107 74 42
Loss on marketable securities ...... -- -- 235
Net loss from debt restructurings .. 1,172 -- 427
Changes in operating assets and
liabilities:
Accounts receivable ............ (814) (807) (6,013)
Equipment inventory ............ (9) (29) (82)
Other assets ................... (74) 2 (133)
Accounts payable, accrued
expenses, and dividends
payable ...................... 1,232 (79) 7,009
Oil and gas production payable . (62) 919 591

--------- --------- ---------
Net cash provided by operating activities 4,401 4,520 13,544

Investing Activities
Capital expenditures, including purchases
and development of properties ........ (36,444) (12,330) (87,793)
Payment for purchase of CGGS,
net of cash acquired ................. -- -- (85,362)
Proceeds from sale of oil and gas
properties and equipment inventory ... 70 2,556 242
Purchase of interest in real estate
partnership .......................... -- (311) --
Proceeds from sale of marketable
securities ........................... -- -- 335
Sale of common stock in Castle Minerals . 371 -- --

--------- --------- ---------
Net cash used in investing activities ... (36,003) (10,085) (172,578)

F-8
<PAGE>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

Year Ended December 31
-----------------------------------
1994 1995 1996
--------- --------- ---------
(In thousands)
Financing Activities
Preferred stock dividends ............... $ (91) $ (366) $ (366)
Issuance of common stock, net of expenses 1,499 10,063 (29)
Purchase of treasury stock, net ......... -- (1) (405)
Proceeds from long-term borrowings ...... 40,906 5,950 305,400
Payments on long-term borrowings ........ (12,659) (5,646) (131,969)
Deferred financing fees ................. (451) (186) (9,688)
Other ................................... -- -- 87
--------- --------- ---------
Net cash provided by financing activities 29,204 9,814 163,030
--------- --------- ---------
Increase (decrease) in cash ............. (2,398) 4,249 3,996
Cash at beginning of year ............... 2,533 135 4,384
--------- --------- ---------
Cash at end of year, including restricted
cash ................................. $ 135 $ 4,384 $ 8,380
========= ========= =========

Supplemental Disclosures
Supplemental disclosures of cash flow
information:
Interest paid ...................... $ 2,150 $ 3,884 $ 3,863
========= ========= =========

Supplemental schedule of noncash investing and financing activities:
During 1996, the Company purchased all of the capital stock of CGGS
Canadian Gas Gathering Systems, Inc. for $85,362,000, net of cash
acquired. In conjunction with the acquisition, liabilities assumed were
as follows (in thousands):
Fair value of assets acquired .......................... $ 123,970
Cash paid for the capital stock ........................ (85,362)
---------
Liabilities assumed .................................... $ 38,608
=========

During 1994, the Company issued $4,574,000 of preferred stock in exchange
for oil and gas producing properties.

See accompanying notes.

F-9
<PAGE>

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 1994, 1995, and 1996

1. Organization and Significant Accounting Policies

Nature of Operations

Abraxas Petroleum Corporation (the Company or Abraxas) is an
independent energy company engaged in the acquisition of and the exploration,
development, and production of crude oil and natural gas primarily along the
Texas Gulf Coast, in the Permian Basin of west Texas, in southwestern Wyoming
and in western Canada, and in the gathering and processing of natural gas
primarily in western Canada. The consolidated financial statements include the
accounts of the Company and its subsidiaries. All significant intercompany
accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles 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.

Marketable Securities

Management determines the appropriate classification of marketable
equity and debt securities at the time of purchase and reevaluates such
designation as of each balance sheet date. Debt securities that the Company has
both the positive intent and ability to hold to maturity are carried at
amortized cost. Debt securities that the Company does not have the positive
intent and ability to hold to maturity and all marketable equity securities are
classified as available-for-sale or trading and carried at fair value.
Unrealized holding gains and losses on securities classified as
available-for-sale are carried as a separate component of shareholders' equity.
Unrealized holding gains and losses on securities classified as trading are
reported in earnings.

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. For further information regarding the Company's swap
arrangements, see Notes 6 and 16.

Equipment Inventory

Equipment inventory consists of casing, tubing, and compressing
equipment and is carried at the lower of cost or market.

F-10
<PAGE>

Oil and Gas Properties

The Company follows the full cost method of accounting for crude oil
and natural gas properties. Under this method, all costs associated with
acquisition of properties and successful as well as unsuccessful exploration and
development activities are capitalized. The Company does not capitalize internal
costs. Depreciation, depletion, and amortization (DD&A) of capitalized crude oil
and natural gas properties and estimated future development costs are based on
the unit-of-production method. Net capitalized costs of crude oil and natural
gas properties are limited to the lower of unamortized cost or the cost ceiling,
defined as the sum of the present value of estimated unescalated future net
revenues from proved reserves discounted at 10 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 being amortized, if any, less
related income taxes. No gain or loss is recognized upon sale or disposition of
crude oil and natural gas properties, except in unusual circumstances.

Unevaluated properties not currently being amortized included in oil
and gas properties were $-0- and $37,268,000 at December 31, 1995 and 1996,
respectively. The properties represented by these costs were undergoing
exploration activities or are properties on which the Company intends to
commence activities in the future. The Company believes that the unevaluated
properties at December 31, 1996 will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time.

Other Property and Equipment

Other property and equipment are recorded on the basis of cost.
Depreciation of gas gathering and processing facilities and 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.

Stock-Based Compensation

Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation," encourages, but does not require, companies to record
compensation cost for stock-based employee compensation plans at fair value. The
Company has chosen to continue to account for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board Opinion 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 (see Note 8).

Foreign Currency Translation

The functional currency for the Company's Canadian operations is the
Canadian dollar. The Company translates the functional currency into U.S.
dollars 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 Cumulative Foreign Exchange
Translation Adjustment in Shareholders' Equity.

F-11
<PAGE>

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 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 major processing
facilities are accrued on a straight-line basis over the life of the property.
The estimated future costs for known environmental remediation requirements are
accrued when it is probable that a liability has been incurred and the amount of
remediation costs can be reasonably estimated. These amounts are the
undiscounted, future estimated costs under existing regulatory requirements and
using existing technology.

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. Revenue from the processing and gathering of natural gas is recognized in
the period the service is performed.

Deferred Financing Fees

Deferred financing fees are being amortized on a level yield basis over
the term of the related debt.

Federal Income Taxes

The Company records income taxes under Financial Accounting Standards
Board Statement No. 109 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.

Net Income (Loss) Per Common Share

Net income (loss) per common share is computed by dividing net income
(loss) (adjusted for dividends on preferred stock) by the weighted average
number of shares of common and common equivalent shares outstanding during the
period. The weighted average number of common and common equivalent shares
includes the number of shares that would be issuable under the Contingent Value
Rights Agreement (CVR Agreement), if the current market value of the Company's
common stock at year-end is less than a specified target price (see Note 7).
Common stock equivalents, including any shares issuable under the CVR Agreement,
are not considered in the computation of periods with a loss, as their effect is
anti-dilutive.

Reclassifications

Certain balances for 1994 and 1995 have been reclassified for
comparative purposes.

F-12
<PAGE>

2. Acquisitions and Divestitures

Wyoming Properties Acquisition

On September 30, 1996, the Company acquired interests in certain
producing crude oil and natural gas properties located in the Wamsutter area of
southwestern Wyoming (the Wyoming Properties) from Enserch Exploration, Inc. The
initially agreed to purchase price of $47,500,000 was adjusted to $45,122,000 to
reflect adjustments of net production revenue which accrued to the Company from
April 1, 1996, the effective date, until closing, net of interest owed by the
Company for the same period and transaction costs. The acquisition was accounted
for as a purchase and the purchase price was allocated to crude oil and natural
gas properties based on the fair values of the properties acquired. The
transaction was financed through borrowings under the Company's bridge facility
referred to in Note 6. Revenues and expenses from the Wyoming Properties have
been included in the consolidated financial statements since September 30, 1996.

CGGS Acquisition

On November 14, 1996, the Company, through its wholly owned subsidiary,
Canadian Abraxas Petroleum Limited (Canadian Abraxas), purchased 100% of the
outstanding capital stock of CGGS Canadian Gas Gathering Systems Inc. (CGGS) for
approximately $85,500,000, net of the CGGS cash acquired and including
transaction costs. CGGS owns producing oil and gas properties in western Canada
and adjacent gas gathering and processing facilities as well as undeveloped
leasehold properties. Immediately after the purchase, CGGS was merged with and
into Canadian Abraxas. The acquisition was accounted for as a purchase and the
purchase price was allocated to the assets and liabilities based on estimated
fair values. The transaction was financed by a portion of the proceeds from the
offering of $215,000,000 of Notes referred to in Note 6. Revenues and expenses
from Canadian Abraxas have been included in the consolidated financial
statements since November 14, 1996.

Grey Wolf Acquisition

In January 1996, the Company made a $3,000,000 investment in Grey Wolf
Exploration Ltd. (Grey Wolf), a privately held Canadian corporation, which in
turn invested in newly issued shares of Cascade Oil and Gas Ltd. (Cascade), an
Alberta, Canada corporation whose shares are traded on the Alberta Stock
Exchange. The Company owns 78% of the outstanding capital stock of Grey Wolf,
and, through Grey Wolf, the Company owns approximately 52% of the outstanding
capital stock of Cascade. The acquisition was accounted for as a purchase and
the purchase price was allocated to the assets and liabilities based on the fair
values. Revenues and expenses have been included in the consolidated financial
statements since January 1996. Certain officers and directors of the Company own
approximately 6% of the common stock of Grey Wolf and serve as directors of Grey
Wolf.

Portilla and Happy Fields Acquisition

In March 1996, the Company sold all of its interest in its Portilla and
Happy Fields to an unrelated purchaser (Purchaser or Limited Partner).
Simultaneously with this sale, the Limited Partner also acquired the 50%
overriding royalty interest in the Portilla Field owned by the Commingled
Pension Trust Fund Petroleum II, the trustee of which is Morgan Guaranty Trust
Company of New York (Pension Fund). In connection with the purchase of both the
Company's interest in the Portilla and Happy Fields and the Pension Fund's
interest in the Portilla Field (together, the Portilla and Happy Properties),
the Limited Partner obtained a loan (Bank Loan) secured by the Properties and
contributed the Properties to Portilla-1996, L.P., a Texas limited partnership
(Partnership). A subsidiary of the Company, Portilla-Happy Corporation
(Portilla-Happy), was the general partner of the Partnership. The aggregate
purchase price received by the Company was $17,600,000, of which $2,000,000 was
used to purchase a minority interest in the Partnership.

F-13
<PAGE>

On November 14, 1996, the Company closed an agreement with the Limited
Partner and certain noteholders (Noteholders) of the Partnership, pursuant to
which the Company obtained the Limited Partner's interest in the Partnership and
the Noteholders' notes in the aggregate principal amount of $5,920,000 (Notes),
resulting in the Company's owning, on a consolidated basis, all of the equity
interests in the Partnership. The aggregate consideration paid to the Limited
Partner and the Noteholders was $6,961,000. The Company also paid off the Bank
Loan which had an outstanding principal balance of approximately $20,051,000,
and assumed a crude oil and natural gas price swap agreement (see Note 16).

As a result of obtaining the Limited Partner's interest in the
Partnership, the Company reacquired those interests in the Portilla and Happy
Fields which it previously owned, as well as the interest in the Portilla Field
previously owned by the Pension Fund. The Company has included in its balance
sheet the amount previously removed from oil and gas properties in connection
with the sale of its interest in the Portilla and Happy Fields during the
quarter ended March 31, 1996, as well as the amount of the purchase price paid
for the Pension Fund's interest in the Portilla Field, and all development
drilling expenditures incurred on the properties, less the amount of DD&A
related to the properties from the formation of the Partnership through the
closing of the transaction. The purchase was financed by a portion of the
proceeds from the offering of the Notes referred to in Note 6. The Company
recorded its share of the net loss of the Partnership from March 1996 to
November 1996 of $513,000. The Company also assumed and wrote off the remaining
deferred financing fees and organization costs of the Partnership. Gross
revenues and expenses from both the Company's original interest in the Portilla
and Happy Fields as well as the interest in the Portilla Field previously owned
by the Pension Fund have been included in the consolidated financial statements
since November 14, 1996.

East White Point and Stedman Island Fields Acquisition

In November 1996, the Company obtained a release of the 50% overriding
royalty interest in the East White Point Field in San Patricia County, Texas and
the Stedman Island Field in Nueces County, Texas from the Pension Fund for
$9,271,000 before adjustment for accrual of net revenue to closing. The
acquisition was accounted for as a purchase and the purchase price was allocated
to crude oil and natural gas properties based on the fair values of the
properties acquired. The transaction was financed through proceeds of the sale
of the Notes referred to in Note 6. Revenues and expenses from these properties
have been included in the consolidated financial statements since November 1,
1996. The Company recorded the net purchase price of approximately $9,271,000 to
its oil and gas properties.

Miscellaneous Working Interests

During 1996, the Company also acquired additional working interests in
certain producing crude oil and natural gas properties in which the Company had
existing working interest ownership. The net purchase price amounted to
approximately $1,221,000. Revenue and expenses have been included in the
consolidated financial statement from the date of purchase.

Texas Gulf Coast Properties Acquisition

In October 1995, the Company acquired additional working interests in
certain producing crude oil and natural gas properties in which the Company had
an existing working interest ownership. The net purchase price to Abraxas
amounted to approximately $635,000. Revenues and expenses have been included in
the consolidated financial statements since October 1, 1995.

F-14
<PAGE>

West Texas Properties Acquisition

In July 1994, the Company acquired from various parties interests in
certain producing crude oil and natural gas properties located in West Texas
(the West Texas Properties). The net purchase price to Abraxas amounted to
approximately $28,242,000 including closing costs of approximately $383,000. The
acquisition was accounted for as a purchase and the purchase price was allocated
to crude oil and natural gas properties based on the fair values of the
properties acquired. The transaction was financed principally by additional
borrowings under the Company's credit agreement with First Union National Bank
of North Carolina (First Union), referred to in Note 6. Revenue and expenses
from the West Texas Properties have been included in the consolidated financial
statements since July 1, 1994.

Overriding Royalty Interest Acquisition

In June 1994, the Company acquired from its prior secured lenders,
Endowment Energy Partners, L.P. (EEP) and Endowment Energy Co-Investment
Partnership (EECIP), 80% of the previously granted overriding royalty interests.
The net purchase price of approximately $5,174,000 consisted of $600,000 cash
and 45,741 shares of the Company's Series B 8% nonvoting cumulative convertible
preferred stock with a par value of $100 per share (Series B Preferred) at the
time of issuance. The preferred shares were recorded at $4,574,100 at the date
of the acquisition. In November 1995, the Company exchanged the Series B
Preferred for an equal number of shares of its Series 1995-B Preferred Stock,
par value $.01 per share, with a stated value of $100 per share. The preferred
shares are convertible into 508,182 shares of the Company's common stock. The
acquisition was accounted for as a purchase, and the purchase price was
allocated to crude oil and natural gas properties based on the fair values of
the properties acquired. The cash portion of the transaction was financed
principally under the Company's credit agreement with First Union. Revenues and
expenses related to these properties have been included in the consolidated
financial statements since July 1, 1994.

The condensed pro forma financial information for the periods presented
below summarize on an unaudited pro forma basis approximate results of the
Company's consolidated operations for the years ended December 31, 1994, 1995
and 1996 assuming the acquisitions of the Wyoming Properties, CGGS, Grey Wolf,
the Portilla and Happy Properties, and the East White Point and Stedman Island
Fields occurred at January 1, 1995; and the acquisition of the West Texas
Properties and Overriding Royalty Interest occurred at January 1, 1994. The pro
forma information does not necessarily represent what the actual consolidated
results would have been for these periods and is not intended to be indicative
of future results.
<TABLE>
<CAPTION>

December 31
-------------------------------
1994 1995 1996
-------- -------- ---------
(In thousands except per
share data)
(Unaudited)

<S> <C> <C> <C>
Revenues ....................................... $ 13,972 $ 46,132 $ 60,077
======== ======== ========

Income (loss) before discontinued operations and
extraordinary items .......................... $ (186) $(16,430) $ (6,665)
======== ======== ========

Net income (loss) .............................. $ (2,693) $(16,430) $ (7,092)
======== ======== ========

Income (loss) per common share:
Before discontinued operations and
extraordinary items ........................ $ (.13) $ (3.54) $ (.98)
Net income (loss) ............................ $ (.71) $ (3.54) $ (1.04)
</TABLE>

Divestiture

In July 1995, the Company sold its C.S. Dean Unit for approximately
$2,550,000.

F-15
<PAGE>

3. Marketable Securities

In May 1993, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 115, "Accounting for Certain Investments
in Debt and Equity Securities" (SFAS 115), effective for fiscal years beginning
after December 15, 1993. At December 31, 1994, the Company's marketable equity
securities were classified as available-for-sale. As of December 31, 1994, the
Company recognized a decrease of approximately $244,000 in shareholders' equity,
representing the recognition in shareholders' equity of unrealized depreciation,
net of taxes, for the Company's investment in equity securities determined to be
available-for-sale, previously carried at the lower of cost or market.

The securities had an original cost of $570,000. In October 1996, the
Company sold its investment in marketable securities, realizing a loss of
$235,000, which was recognized in the statement of operations for the year ended
December 31, 1996.

4. Property and Equipment

The major components of property and equipment, at cost, are as
follows:

Estimated
Useful Life 1995 1996
------------ -------- ---------
Years (In thousands)

Land, buildings, and improvements .. 15 $ 177 $ 269
Crude oil and natural gas properties -- 104,127 268,358
Natural gas processing plants ...... 18 -- 40,100
Equipment and other ................ 7 693 1,316
-------- --------
$104,997 $310,043
======== ========

5. Related Party Transactions

Accounts receivable from affiliates, officers, and shareholders
represent amounts receivable relating to joint interest billings on properties
which the Company operates and advances made to officers.

In connection with a note payable to the Company's President, principal
and interest payments amounted to $333,000 and $355,000 in the years ended
December 31, 1994 and 1995, respectively. The note was fully paid in 1995.

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 employees of the Company from time
to time at $385 per hour. The Company paid Wind River a total of $81,000 and
$101,000 for use of the plane during 1995 and 1996, respectively.

The Company's President and certain directors of the Company were
founders of Grey Wolf and in April 1995 purchased 900,000 shares of the capital
stock of Grey Wolf (initially representing 39% of the outstanding shares) for an
aggregate of CDN$90,000 (or CDN$0.10 per share) in cash. In January 1996, the
Company purchased 20,325,096 shares of the capital stock of Grey Wolf
(representing 78% of the outstanding shares) for an aggregate of $3,000,000
(approximately CDN$4.1 million or CDN$.20 per share) in cash. The Company's
President and certain directors, as well as the two principal officers of Grey
Wolf, currently own 13.8% of the issued and outstanding capital stock of Grey
Wolf. In addition, the Company's President owns options to purchase up to
450,000 shares of Grey Wolf's capital stock at an exercise price of CDN$.10 per
share.

F-16
<PAGE>

In January 1996, Grey Wolf purchased newly issued shares of Cascade
representing 66 2/3% of Cascade's capital stock. Certain of the Company's
directors as well as the two principal officers of Grey Wolf own options to
purchase in the aggregate up to 2,600,000 shares of capital stock of Cascade at
a exercise price of CDN$.20 per share, and the Company's President owns options
to purchase up to 800,000 shares of Cascade's capital stock at an exercise price
of CDN$.34 per share.
Cascade currently has 61,365,000 shares of capital stock outstanding.

6. Long-Term Debt

Long-term debt consists of the following:

December 31
1995 1996
-------- ---------
(In thousands)

11.5% Senior Notes due 2004 (see below) .................. $ -- $215,000
Credit facility due to Bankers Trust Company, ING
Capital and Union Bank of California (see below) ....... -- --
Revolving lines of credit due under the First Union credit
agreement (see below) .................................. 35,557 --
Term notes due under the First Union credit agreement
(see below) ............................................ 6,000 --
Other .................................................... 44 32
-------- --------
41,601 215,032
Less current maturities .................................. -- --
-------- --------
$ 41,601 $215,032
======== ========

On November 14, 1996, the Company and Canadian Abraxas completed the
sale of $215,000,000 aggregate principal amount of Senior Notes due November 1,
2004 (Notes). Interest at 11.5% is payable semi-annually in arrears on May 1 and
November 1 of each year, commencing on May 1, 1997. The Notes are general
unsecured obligations of the Company and Canadian Abraxas and rank pari passu in
right of payment to all future subordinated indebtedness of the Company and
Canadian Abraxas. The Notes are, however, effectively subordinated in right of
payment to all existing and future secured indebtedness to the extent of the
value of the assets securing such indebtedness. The Company and Canadian Abraxas
are joint and several obligors on the Notes. The Notes are redeemable, in whole
or in part, at the option of the Company and Canadian Abraxas on or after
November 1, 2000, at the redemption price of 105.75% through October 31, 2001,
102.87% through October 31, 2002 and 100.00% thereafter plus accrued interest.
In addition, any time on or prior to November 1, 1999, the Company and Canadian
Abraxas may redeem up to 35% of the aggregate principal amount of the Notes
originally issued with the cash proceeds of one or more equity offerings at a
redemption price of 111.5% of the aggregate principal amount of the Notes to be
redeemed plus accrued interest, provided, however, that after giving effect to
such redemption, at least $139,750,000 aggregate principal amount of Notes
remains outstanding. The Notes were issued under the terms of an Indenture dated
November 14, 1996 that contains, among others, certain covenants which generally
limit the ability of the Company to incur additional indebtedness other than
specific indebtedness permitted under the Indenture, including the Credit
Facility discussed below, provided however, if no event of default is
continuing, the Company may incur indebtedness if after giving pro forma effect
to the incurrence of such debt both the Company's consolidated earnings before
interest, taxes, depletion and amortization (EBITDA) coverage ratio would be
greater than 2.25 to 1.0 if prior to November 1, 1997, and at least equal to 2.5
to 1.0 thereafter and the Company's adjusted consolidated net tangible assets as
defined are greater than 150% of the aggregate consolidated indebtedness of the
Company. The Indenture also contains other covenants affecting the Company's
ability to pay dividends on its common stock, sell assets and incur liens.

F-17
<PAGE>

On September 30, 1996, the Company entered into a credit facility with
Bankers Trust Company (BTCo) and ING Capital (together the Lenders), providing a
bridge facility in the total amount of $90,000,000 and borrowed $85,000,000
which was used to repay all amounts due under the First Union credit agreement
and to finance the purchase of the Wyoming Properties.

On November 14, 1996, the Company repaid all amounts outstanding under
the bridge facility with proceeds from the offering of $215,000,000 of Notes
described above and entered into an amended and restated credit agreement
(Credit Facility) with the Lenders and Union Bank of California. The Credit
Facility provides for a revolving line of credit with an initial availability of
$20,000,000, subject to a borrowing base condition. No amounts were outstanding
on December 31, 1996.

Commitments available under the Credit Facility are subject to
borrowing base redeterminations to be performed semi-annually and, at the option
of each of the Company and the Lenders, one additional time per year. Amounts
due under the Credit Facility will be secured by the Company's oil and gas
properties and plants. Any outstanding principal balance in excess of the
borrowing base will be due and payable in three equal monthly payments after a
borrowing base redetermination. The borrowing base will be determined in the
agent's sole discretion, subject to the approval of the Lenders, based on the
value of the Company's reserves as set forth in the reserve report of the
Company's independent petroleum engineers, with consideration given to other
assets and liabilities.

The applicable interest rate charged on the outstanding balance of the
Credit Facility is based on a facility usage grid. If the borrowings under the
Credit Facility represent an amount less than or equal to 33.3% of the available
borrowing base, then the applicable interest rate charged on the outstanding
balance will be either (a) an adjusted rate of the London Inter-Bank Offered
Rate ("LIBOR") plus 1.25% or (b) the prime rate of the agent (which is based on
the agent's published prime rate) plus 0.50%. If the borrowings under the Credit
Facility represent an amount greater than or equal to 33.3% but less than 66.7%
of the available borrowing base, then the applicable interest rate on the
outstanding principal will be either (a) LIBOR plus 1.75% or (b) the prime rate
of the agent plus 0.50%. If the borrowings under the Credit Facility represent
an amount greater than or equal to 66.7% of the available borrowing base, then
the applicable interest rate on the outstanding principal will be either (a)
LIBOR plus 2.00% or (b) the prime rate of the agent plus 0.50%. LIBOR elections
can be made for periods of one, three or six months.

The Credit Facility contains a number of covenants that, among other
things, restrict the ability of the Company to (i) incur certain indebtedness or
guarantee obligations, (ii) prepay other indebtedness including the Notes, (iii)
make investments, loans or advances, (iv) create certain liens, (v) make certain
payments, dividends and distributions, (vi) merge with or sell assets to another
person or liquidate, (vii) sell or discount receivables, (viii) engage in
certain intercompany transactions and transactions with affiliates, (ix) change
its business, (x) experience a change of control and (xi) make amendments to its
charter, by-laws and other debt instruments. In addition, under the Credit
Facility the Company is required to comply with specified financial ratios and
tests, including minimum debt service coverage ratios, maximum funded debt to
EBITDA tests, minimum net worth tests and minimum working capital tests. The
Company is obligated to pay the Lenders on a quarterly basis a commitment fee of
0.50% per annum on the average unused portion of the commitment in effect from
time to time. The Credit Facility contains customary events of default,
including nonpayment of principal, interest or fees, violation 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 and change of control.

F-18
<PAGE>

As part of the bridge facility, the Company entered into an interest
rate swap agreement (the Swap) covering the period from September 18, 1996 to
August 18, 1998. The Swap effectively changes the interest rate on $25,000,000
of floating rate debt to a fixed rate of 6.15% per annum for that time period.
Net payments due under this agreement are included as adjustments to interest
expense. At December 31, 1996, the fair value of this Swap, as determined by
BTCo was approximately $200,000 and has been recorded as interest expense at
December 31, 1996. The Company is exposed to credit loss in the event of
nonperformance by the counterparty. The amount of such exposure is generally the
unrealized gains in such agreement.

In June 1994, the Company entered into a credit agreement with First
Union and secured advances adequate to extinguish the total debt and accrued
interest owed to the Company's previous lenders. The prepayment resulted in the
Company recording an extraordinary debt extinguishment charge of $1,172,000,
representing the reduction of the deferred financing fees related to the prior
debt. At December 31, 1995, the Company's borrowings under the credit agreement
were $41,557,000. The borrowings were composed of advances of $12,657,000 and
$22,900,000 under the revolving lines of credit which were due June 30, 1997,
and $6,000,000 under the term notes which were also due June 30, 1997. The
interest rate for the revolving credit lines was, at the option of the Company,
either (a) the higher of First Union prime plus 1/4% or the federal funds rate
plus 3/4%, floating, payable monthly, or (b) LIBOR plus 2 1/4% (30-, 60-, 90-,
and 180-day options), with interest payable the earlier of maturity of each
LIBOR tranche or quarterly. The interest rate for the term notes were, at the
option of the Company, either (a) the higher of First Union prime plus 3/4% or
the federal funds rate plus 1 1/4%, floating, payable monthly, or (b) LIBOR plus
3 1/4% (30-, 60-, 90-, and 180-day options), with interest payable the earlier
of maturity of each LIBOR tranche or quarterly. At December 31, 1995, the
$12,657,000 revolver carried interest at 8.19%, the $22,900,000 revolver carried
interest at 8.06%, and the term notes at 8.16%. The revolvers provided for
borrowing based principally on the Company's crude oil and natural gas reserve
base, which was $44,000,000 at December 31, 1995 and such borrowings were
secured by a first-priority mortgage on all of the Company's crude oil and
natural gas properties and gas plants, as well as a security interest in
accounts receivable, inventory, contracts, and general intangibles, and are
guaranteed by the Company. As discussed above, in September 1996, the Company
entered into a new credit facility and extinguished the total debt and accrued
interest owed to First Union. The prepayment resulted in the Company recording
an extraordinary debt extinguishment charge of $427,000 representing the
reduction of the deferred financing fees related to the debt.

The Company's principal source of funds to meet debt service and
capital requirements is net cash flow provided by operating activities, which is
sensitive to the prices the Company receives for its crude oil and natural gas.
The Company has recently entered into hedge agreements to reduce its exposure to
price risk in the spot market for natural gas. However, a substantial portion of
the Company's production will remain subject to such price risk. Additionally,
significant capital expenditures are required for drilling and development, and
other equipment additions. The Company believes that cash provided by operating
activities and other financing sources, including, if necessary, the sale of
certain assets and additional long-term debt, will provide adequate liquidity
for the Company's operations, including its capital expenditure program, for the
next twelve months. No assurance, however, can be given that the Company's cash
flow from operating activities will be sufficient to meet planned capital
expenditures and debt service in the future. Should the Company be unable to
generate sufficient cash flow from operating activities to meet its obligations
and make planned capital expenditures, the Company could be forced to reduce
such expenditures or sell assets in order to meet its obligations.

During 1996, the Company capitalized $465,000 of interest expense.

The fair value of the Notes approximates their carrying value as of
December 31, 1996. The Company has approximately $60,000 of standby letters of
credit and a $30,000 performance bond open at December 31, 1996. Approximately
$90,000 of cash is restricted and in escrow related to the letters of credit and
bond.

F-19
<PAGE>

7. Shareholders' Equity

Common Stock

Holders of common stock are entitled to one vote for each share and are
not entitled to preemptive rights to subscribe to additional shares of common
stock issued by the Company. Holders are entitled to receive dividends as may be
declared by the Board of Directors, subject to the rights of holders of
preferred stock and the terms of the Company's credit agreement, which restrict
the payment of dividends.

In 1994, the Board of Directors adopted a Shareholders' 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 $20 one-half of one share of
common stock of the Company having a value of four 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.

In November 1995, the Company issued 1,330,000 units, each consisting
of one share of common stock and one Contingent Value Right (CVR), through a
private placement, resulting in net proceeds of $10,063,000. Each CVR allows the
holder the right to acquire additional shares of common stock under certain
circumstances. See further discussion of CVRs below. Loss per share, calculated
on a supplemental basis as if the foregoing event had occurred at the beginning
of 1995, would have been $(.19) for the year ended December 31, 1995. The
supplemental earnings per share assumes that interest expense would have been
reduced by $456,000 from the prepayment of $5,300,000 of long-term debt from the
proceeds of the issuance of the units for the year ended December 31, 1995.

Preferred Stock

In June 1994, in connection with the Company's acquisition of the
overriding royalty interest from EEP and EECIP, 45,741 shares of the Company's
Series B 8%, nonvoting cumulative convertible preferred stock with a par value
of $100 were issued. The preferred shares are convertible into 508,182 shares of
the Company's common stock. Preferred stock dividends during 1995 and 1996
amounted to $366,000. During 1995, the Company exchanged the Series B 8%,
nonvoting cumulative convertible preferred stock for an equal number of shares
of Series 1995-B cumulative convertible preferred stock which have a par value
of $.01 per share and a stated value of $100 per share. The Board of Directors
of the Company is authorized to approve the issuance of one or more classes or
series of preferred stock without further authorization of the Company's
shareholders.

Contingent Value Rights (CVR)

The CVRs were issued under the CVR Agreement between the Company, the
purchasers, and First Union, as rights agents. The CVR Agreement provides that,
subject to adjustment as described below, the Company shall issue for each CVR
on the Extended Maturity Date (November 17, 1997), a number of shares of common
stock, if any, equal to (a) the Target Price ($12.50 on the Extended Maturity
Date) minus the current market value divided by (b) the current market value,
provided, however, that in no event shall more than 1.5 shares of common stock
be issued in exchange for each CVR at the Extended Maturity Date. Such
determination by the Company shall be final and binding on the Company and the
holders of CVRs.

F-20
<PAGE>

If the median of the average prices of the common stock for the three
20-trading day periods immediately preceding the Extended Maturity Date, equals
or exceeds $12.50 on the Extended Maturity Date, no shares of the common stock
will be issuable with respect to the CVRs. In addition, the CVRs will terminate
if the per share market value equals or exceeds the Target Price for any period
of 30 consecutive trading days during the period from and after November 17,
1996 to and including November 17, 1997.

In the event that the Company determines that no shares of the common
stock are issuable with respect to the CVRs to such holders, the CVRs shall
terminate and become null and void and the holders shall have no further rights
with respect thereto. If the Maturity Date of the CVR Agreement had been
December 31, 1996, an aggregate of 1,013,060 shares of common stock would have
been issued to the holders of the CVRs.

Should any additional shares of common stock be required to be issued
under the terms of the CVR Agreement, such issuance will be considered to be an
adjustment to the original sales price per share received in connection with the
sale of the associated common shares; accordingly, the Company will increase its
common stock account for the par value related to the additional shares at the
time such shares are issued with a corresponding decrease in additional paid-in
capital account.

Treasury Stock

During the year ended December 31, 1996, the Company purchased 74,640
shares of its common stock at a cost of $405,000, which are being held as
treasury stock.

8. Stock Option Plans and Warrants

Stock Options

The Company grants options to its officers, directors, and key
employees under its 1984 Incentive Stock Option Plan, Non-Qualified Stock Option
Plan, Key Contributor Stock Option Plan, Long-Term Incentive Plan, and Director
Stock Option Plan.

The Company has elected to follow Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related
Interpretations in accounting for its employee stock options because, as
discussed below, the alternative fair value accounting provided for under FASB
Statement No. 123, "Accounting for Stock-Based Compensation," requires use of
option valuation models that were not developed for use in valuing employee
stock options. Under APB 25, because the exercise price of the Company's
employee stock options equals the market price of the underlying stock on the
date of grant, no compensation expense is recognized.

The Company's various stock option plans have authorized the grant of
options to management and directors personnel for up to approximately 795,000
shares of the Company's common stock. All options granted have ten year terms
and vest and become fully exercisable over four years of continued service at
25% on each anniversary date.

Pro forma information regarding net income and earnings per share is
required by Statement 123, which also requires that the information be
determined as if the Company has accounted for its employee stock options
granted subsequent to December 31, 1994 under the fair value method of that
Statement. The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model with the following weighted-average
assumptions for 1995 and 1996, respectively: risk-free interest rates of 6.25%
and 6.25%; dividend yields of -0-% and -0-%; volatility factors of the expected
market price of the Company's common stock of .383 and .383; and a
weighted-average expected life of the option of six years.

F-21
<PAGE>

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 (in thousands except for earnings per share
information):

1995 1996
------------ -----------
(In thousands)

Pro forma net income (loss) .................. $ (1,652) $ 884
Pro forma earnings per share:
Primary .................................... $ (.36) $ .13

Because Statement 123 is applicable only to options granted subsequent
to December 31, 1994, its pro forma effect will not be fully reflected until
1997.

A summary of the Company's stock option activity, and related
information for the years ended December 31 follows:
<TABLE>
<CAPTION>

1994 1995 1996
----------------------------- ----------------------------- -----------------------------
Weighted-Average Weighted-Average Weighted-Average
Options Exercise Price Options Exercise Price Options Exercise Price(1)
(000s) (000s) (000s)
---------- ------------------ ---------- ------------------ --------- ------------------

<S> <C> <C> <C> <C> <C> <C>
Outstanding-beginning of
year .................... 133 $ 6.62 103 $ 7.93 219 $ 6.71 (1)
Granted ................... 27 10.45 158 9.50 358 6.58
Exercised ................. (38) 4.64 - - (2) 6.75
Forfeited ................. (19) 8.91 (42) 9.86 (24) 9.21
---------- ---------- ---------

Outstanding-end of year ... 103 $ 7.93 219 $ 8.69 551 $ 6.63
========== ========== =========

Exercisable at end of year 28 $ 7.43 53 $ 8.06 93 $ 6.65
========== ========== =========

Weighted-average fair
value of options
granted during the year $ 2.85 $ 3.46
</TABLE>

Exercise prices for options outstanding as of December 31, 1996 ranged
from $5.00 to $7.50. The weighted-average remaining contractual life of those
options is 8.6 years.

(1) In March 1996, the Company amended the exercise price to $6.75 per
share on all previously issued options with an exercise price greater than $6.75
per share.

F-22
<PAGE>

Stock Awards

In addition to stock options granted under the plans described above,
the Long-Term Incentive Plan also provides for the right to receive compensation
in cash, awards of common stock, or a combination thereof. In 1995 and 1996, the
Company made direct awards of common stock of 4,800 shares and 1,000 shares,
respectively.

The Company also has adopted the Restricted Share Plan for Directors
which provides for awards of common stock to nonemployee 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 1995 and 1996, the Company made direct awards of common stock of
3,072 shares and 4,050 shares, respectively.

During 1996, the Company's shareholders approved the Abraxas Petroleum
Corporation Director Stock Option Plan (Plan), which authorizes the grant of
nonstatutory options to acquire an aggregate of 104,000 common shares to those
persons who are directors and not officers of the Company. Under the Plan, each
of the seven eligible directors was granted an option to purchase 8,000 common
shares at $6.75. These options are included in the above table.

Stock Warrants

In connection with the EEP and EECIP financing agreements entered into
in 1992 and 1993, the Company granted stock warrants covering 90,000 shares at
$5.25 per share and 135,000 shares at $7.00 per share. During 1994, 211,500
warrants were exercised to purchase common stock for $1,323,000. In 1995 and
1996, no warrants were exercised by EEP or EECIP.

In connection with an amendment and increase in the facility under the
credit agreement with First Union and the extension of the due date on the term
note, the Company granted stock warrants to First Union covering 424,000 shares
of its common stock at an average price of $9.79 a share. The warrants are
exercisable in whole or in part through December 1999 and are nontransferable
without the consent of the Company.

At December 31, 1996, the Company has approximately 6,600,000 shares
reserved for future issuance for conversion of its stock options, warrants,
Rights, preferred stock, CVRs, and incentive plans for the Company's directors
and employees.

F-23
<PAGE>

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:

December 31
---------------------
1995 1996
---------- --------
(In thousands)
Deferred tax liabilities:
Full cost pool, including intangible
drilling costs ........................ $ 661 $ 34,298
State taxes ............................. 187 187
Other ................................... 101 61
-------- --------
Total deferred tax liabilities ............ 949 34,546
Deferred tax assets:
Depletion ............................... 242 431
Net operating losses .................... 6,163 6,831
Other ................................... 13 12
-------- --------
Total deferred tax assets ................. 6,418 7,274
Valuation allowance for deferred tax assets (5,656) (5,656)
-------- --------
Net deferred tax assets ................... 762 1,618
-------- --------
Net deferred tax liabilities .............. $ 187 $ 32,928
======== ========

Significant components of the provision for income taxes are as
follows:
Current Deferred
--------- ---------

Federal ................................. $ - $ -
State ................................... - -
Foreign ................................. 176 -
------- --------
$ 176 $ -
======= ========

At December 31, 1996, the Company had, subject to the limitations
discussed below, $20,094,000 of net operating loss carryforwards for U.S. tax
purposes, of which it is estimated a maximum of $17,562,000 may be utilized
before it expires. These loss carryforwards will expire from 2002 through 2010
if not utilized. At December 31, 1996, the Company had approximately $830,000 of
net operating loss carryforwards for Canadian tax purposes which expire in 2003.

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 of the Internal Revenue Code of 1986, as amended (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
$4,909,000 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 $1,121,000
acquired in the acquisition are limited to approximately $115,000 per year.

F-24
<PAGE>

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 net operating loss carryforwards generated through October 1993(including
those subject to the 1991 and 1992 ownership changes discussed above) of
$8,224,000 will be limited to approximately $1,034,000 per year, subject to the
lower limitations described above. Of the $8,224,000 net operating loss
carryforwards existing at October 1993, it is anticipated that the maximum net
operating loss that may be utilized before it expires is $5,692,000. Future
changes in ownership may further limit the use of the Company's carryforwards.

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 $5,656,000 and $5,657,000 for deferred tax assets at
December 31, 1995 and 1996, respectively.

The reconciliation of income tax attributable to continuing operations
computed at the U.S. federal statutory tax rates to income tax expense is:

December 31
---------------------------------
1994 1995 1996
------- -------- --------
(In thousands)

Tax (expense) benefit at U.S.
statutory rates (34%) .......... $ (38) $ 411 $ (743)
(Increase) decrease in deferred
tax asset valuation allowance .. 31 (174) (1)
Higher effective rate of foreign
operations ..................... - - (49)
Percentage depletion ............. - - 189
Other ............................ 7 (237) 428
------- -------- --------
$ - $ - $ (176)
======= ======== ========
10. Commitments and Contingencies

Operating Leases

During 1995, the Company entered into a noncancelable lease for new
primary office space which, as amended, provides for payments of $15,700 per
month through January 1998, $13,700 per month through March 2000, and $19,000
per month through March 2006, at which time the lease expires.

During the years ended December 31, 1994, 1995, and 1996, the Company
incurred rent expense of approximately $108,000, $103,000, and $179,000,
respectively. Future minimum rental payments are as follows at December 31,
1996:

1997 ..................................... $ 300,000
1998 ..................................... 300,000
1999 ..................................... 300,000
2000 ..................................... 300,000
2001 ..................................... 340,000
Thereafter ............................... 970,000

Aggregate future minimum rentals to be received under noncancelable
subleases as of December 31, 1996 amount to approximately $57,000.

F-25
<PAGE>

Contingencies

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, 1996, 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's financial statements.

11. Discontinued Operations

In January 1995, the Company entered into a plan to discontinue the
operations of its coal properties and commenced the permanent closing of the
mine. As of December 31, 1994, the Company wrote off its investment in its coal
properties and related equipment, eliminated the related minority interest in
the coal entities, and established a liability of $150,000 pursuant to a plan to
discontinue operations for future costs related to closing the mine.
Additionally, during 1994 the Company sold its interest in Castle Minerals,
Inc., which was acquired in 1992 to finance the coal operations, for $371,000,
net of expenses related to the sale. The Company recorded a loss on these
transactions in 1994 of $988,000. The revenues from coal sales for the years
ended 1994 and 1995 were $104,310 and $-0-, respectively.

12. Quarterly Results of Operations (Unaudited)

Selected results of operations for each of the fiscal quarters during
the years ended December 31, 1995 and 1996 are as follows:
<TABLE>
<CAPTION>

1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------------- ----------------- ---------------- ----------------
(In thousands, except per share data)
<S> <C> <C> <C> <C>
Year Ended December 31, 1995
Net revenue .................... $ 3,237 $ 3,402 $ 3,289 $ 3,889
Operating income ............... 763 931 647 542
Net (loss) ..................... (225) (83) (375) (525)
Loss per common share .......... (.07) (.04) (.10) (.13)
Year Ended December 31, 1996
Net revenue .................... 4,477 3,305 3,616 15,255
Operating income ............... 1,486 365 744 6,231
Income (loss) before
extraordinary item ........... 599 (240) (236) 1,817
Net income (loss) .............. 599 (240) (605) 1,759
Earnings (loss) per common
share before extraordinary
item ......................... .08 (.06) (.06) .25
Earnings (loss) per common and
common equivalent share ...... .08 (.06) (.12) .24
</TABLE>

During the fourth quarter of 1996, the Company completed several
acquisitions as described in Note 2 which effected net revenues, gross profit
and net income.

Certain previously reported financial information has been reclassified
to conform with the current presentation.

F-26
<PAGE>

13. Benefit Plans

The Company has a defined contribution plan (401(k)) covering all
eligible employees of the Company. No contributions were made by the Company
during 1994 or 1995. During 1996, the Company contributed 2,500 shares of its
common stock to the Plan and recorded the fair value of $12,500 as compensation
expense. 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 overall contribution is limited to the
lesser of 20% of the employee's annual compensation or $9,240.

In January 1995, the Company created the Technical Employees Incentive
Bonus Plan, whereby technical employees have an incentive to find and develop
crude oil and natural gas reserves on an economic basis beneficial to the
Company and its shareholders. Participants are any technical employees
(geologist, geophysicist, engineer) not covered by another incentive bonus plan.
A participant may earn a monetary bonus of up to 65% of the participant's base
salary each year. The bonuses are determined in the first quarter of each year
and are based upon the amount of new proved developed producing reserves booked
each year on approved exploration and exploitation projects taking into
consideration the cost per equivalent barrel of developing the new reserves.
During 1995 and 1996, the Company incurred no bonus expense.

14. Summary Financial Information of Canadian Abraxas Petroleum Ltd.

The following is summary financial information of Canadian Abraxas, a
wholly owned subsidiary of the Company. Canadian Abraxas is jointly and
severally liable for the entire balance of the Notes ($215,000,000), of which
$84,612,000 was utilized by Canadian Abraxas in connection with the acquisition
of CGGS. The Company has not presented seperate financial statements and other
disclosures concerning Canadian Abraxas because management has determined that
such information is not material to the holders of the Notes.

Assets Liabilities and Shareholder's Equity
- ------------------------------------- ----------------------------------------
(In thousands)

Total current assets .... $ 6,174 Total current liabilities ... $ 3,624
Oil and gas properties .. 115,671 11.5% Senior Notes due 2004 . 84,612
Other assets ............ 3,302 Other liabilities ........... 34,797
-----------
$ 125,147 Shareholder's equity ........ 2,114
===========
----------
$ 125,147
==========

Revenues ................................................ $ 3,972
Operating costs and expenses ............................ (2,292)
Interest expense ........................................ (1,331)
Other income (expense) .................................. 23
Income tax .............................................. (175)
-----------
Net income ........................................... $ 197
===========

F-27
<PAGE>

15. Business Segments

The Company conducts its operations through two industry segments, the
exploration for and the acquisition, development and production of crude oil and
natural gas (E&P) and the processing of natural gas (Processing). The E&P
segment acquires and explores for, develops, produces and markets crude oil,
condensate natural gas liquids and natural gas. The Processing segment processes
natural gas owned by third parties. The Company's significant E&P operations are
located in the Texas Gulf Coast, the Permian Basin of west Texas, southwestern
Wyoming and western Canada. The Processing segment engages in natural gas
gathering and processing operations. Natural gas gathering operations involve
locating and contracting for natural gas supplies produced from crude oil and
natural gas fields and the operation and maintenance of a gathering system of
pipelines that connect such natural gas supply sources to natural gas processing
plants. Natural gas processing involves the custom processing of natural gas for
third parties. Segment income excludes interest income, interest expense and
unallocated general corporate expenses. Identifiable assets are those assets
used in the operations of the segment. Corporate assets consist primarily of
deferred financing fees and other property and equipment. The Company's revenues
are derived primarily from the sale of crude oil, condensate, natural gas
liquids and natural gas to marketers and refiners and from processing fees from
the custom processing of natural gas. As a general policy, collateral is not
required for receivables; however, the credit of the Company's customers is
regularly assessed. The Company is not aware of any significant credit risk
relating to its customers and has not experienced significant credit losses
associated with such receivables.

In 1996 seven customers accounted for approximately 66% of oil and
natural gas production revenues and three customers accounted for approximately
54% of gas processing revenues. In 1995 and 1994 one customer accounted for
approximately 20% and 35% of oil and natural gas production revenues,
respectively.

Business segment information about the Company's 1996 operations in
different industries is as follows:
<TABLE>
<CAPTION>

E&P Processing Total
----------------- ---------------- ----------------
(In thousands)

<S> <C> <C> <C>
Revenues ..................................... $ 26,053 $ 600 $ 26,653
================= ================ ================

Operating profit ............................. $ 8,737 $ 19 $ 8,756
================= ================
General corporate expenses ................... (119)
Interest expense and amortization of deferred
financing fees ............................ (6,521)
----------------
Income from continuing operations before
income taxes ............................ $ 2,116
================

Identifiable assets .......................... $ 253,707 $ 40,700 $ 294,407
================= ================
Corporate assets ............................. 10,435
----------------
Total assets .............................. $ 304,842
================
</TABLE>

Depreciation and depletion for E&P and Processing was approximately
$9,143,000 and $291,000, respectively. Capital expenditures for E&P and
Processing were $145,600,000 and $27,300,000, respectively.

During 1994 and 1995 the Company's operations were entirely in the E&P
segment.

F-28
<PAGE>

Business segment information about the Company's 1996 operations in
different geographic areas is as follows:

<TABLE>
<CAPTION>
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)

<S> <C> <C> <C>
Revenues ................................... $ 21,999 $ 4,654 $ 26,653

Operating profit ........................... $ 7,062 $ 1,694 $ 8,756
================== ==================
General corporate expenses ................. (119)
Interest expense and amortization of
deferred financing fees ................. (6,521)
===================
Income from continuing operations before
income taxes .......................... $ 2,116
===================

Identifiable assets at December 31, 1996 ... $ 168,141 $ 126,266 $ 294,407
================== ==================
Corporate assets ........................... 10,435
-------------------
Total assets ............................ $ 304,842
===================
</TABLE>

During 1994 and 1995 the Company's operations were entirely in the
United States.

16. Commodity Swap Agreements

The Company enters into commodity swap agreements (Hedge Agreements) to
reduce its exposure to price risk in the spot market for crude oil and natural
gas. Pursuant to the Hedge Agreements, either the Company or the counterparty
thereto is required to make payment to the other at the end of each month.
During the period from March 1996 through November 1996, payments were exchanged
equal to the product of 5,000 MMBtu (million Btu's) of natural gas per day and
the difference between a specified fixed price and a variable price for natural
gas based on the arithmetic average of the last three trading days' settlement
price quoted for natural gas contracts on the New York Mercantile Exchange
(NYMEX). This Hedge Agreement provided for the Company to make payments to the
counterparty to the extent that the market price exceeds the fixed price of
$1.747 per MMBtu (thousand Btu's) and for the counterparty to make payments to
the Company to the extent the market price was less than $1.747 per MMBtu. A
loss of $511,000 was incurred during the period of hedged production.

In November 1996, the Company assumed Hedge Agreements extending
through October 2001 with a counterparty involving the following notional
quantities and fixed prices:
<TABLE>
<CAPTION>

Crude Oil Natural Gas
-------------------------------------- --------------------------------------
Notional Quantity Notional Quantity
per Month Fixed per Month (MMBtu) Fixed
(barrels) Price Price
(barrel) (MMBtu)
------------------- ------------------ ------------------ ------------------

<S> <C> <C> <C> <C>
1996 20,060 $ 17.53 87,406 $ 1.925
1997 15,810 $ 17.20 53,712 $ 1.797
1998 13,175 $ 17.20 36,601 $ 1.793
1999 11,050 $ 17.47 24,489 $ 1.820
2000 9,180 $ 17.78 18,794 $ 1.872
2001 8,160 $ 18.08 14,850 $ 1.902

</TABLE>

F-29
<PAGE>

These Hedge Agreements provide for the Company to make payments to the
counterparty to the extent the market prices determined based on the price for
west Texas intermediate light sweet crude oil on the NYMEX for crude oil and the
Inside FERC, Tennessee Gas Pipeline Co.; Texas (Zone O) price for natural gas
exceeds the above fixed prices and for the counterparty to make payments to the
Company to the extent the market prices are less than the above fixed prices.
The Company accounts for the related gains or losses (a loss of $453,000 in
1996) in crude oil and natural gas revenue in the period of the hedged
production. The average notional quantity of crude oil and natural gas under the
Hedge Agreements each month for 1997 is equal to approximately 19% and .5%,
respectively, of the Company's expected monthly production for 1997 based on the
Company's January 1, 1997 reserve reports. At December 31, 1996, the estimated
fair market value of the Hedge Agreements is a loss of $2,460,000.

In January 1997, the Company effectively collared its crude oil prices
between $19.00 and $25.60 per barrel on 1,000 barrels per day from February 1997
through December 1997.

17. Subsequent Event

On January 31, 1997 the Company sold its interest in its crude oil and
natural gas property, plant, and equipment in the Hoole area in Alberta, Canada
for approximately $9,300,000.

18. Supplemental Oil and Gas Disclosures (Unaudited)

The accompanying table presents information concerning the Company's
crude oil and natural gas producing activities as required by Financial
Accounting Standards 69, "Disclosures about Oil and Gas Producing Activities."
Capitalized costs relating to oil and gas producing activities are as follows:

December 31
----------------------
1995 1996
--------- ---------
(In thousands)

Proved crude oil and natural gas properties $ 104,127 $ 231,090
Unproved properties ....................... -- 37,268
--------- ---------
Total ................................... 104,127 268,358
Accumulated depreciation, depletion, and
amortization, and valuation allowances .. (29,651) (38,368)
--------- ---------
Net capitalized costs ................. $ 74,476 $ 229,990
========= =========

F-30
<PAGE>

Costs incurred in oil and gas property acquisitions, exploration and
development activities are as follows:
<TABLE>
<CAPTION>

Years Ended December 31

1994 1995 1996
------------------------------ ------------------------------ ------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
-------- -------- -------- -------- -------- -------- -------- -------- --------
(In thousands)

<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Property acquisition costs:
Proved .................. $ 33,597 $ 33,597 $ -- $ 719 $ 719 $ -- $ 87,005 $ 37,609 $ 49,396
Unproved ................ 5 5 -- -- -- -- 37,268 8,230 29,038
-------- -------- -------- -------- -------- -------- -------- -------- --------

$ 33,602 $ 33,602 $ -- $ 719 $ 719 $ -- $124,273 $ 45,839 $ 78,434
======== ======== ======== ======== ======== ======== ======== ======== ========

Property development and
exploration costs ....... $ 7,151 $ 7,151 $ -- $ 11,398 $ 11,398 $ -- $ 18,133 $ 18,115 $ 18
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>

The results of operations for oil and gas producing activities are as
follows:
<TABLE>
<CAPTION>

Years Ended December 31
---------------------------------------------------------------------------------------------
1994 1995 1996
---------------------------- ----------------------------- ------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
--------- --------- -------- ---------- --------- ------- ---------- -------- --------
(In thousands)

<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues ................... $ 11,114 $ 11,114 $ - $ 13,660 $ 13,660 $ - $ 25,749 $ 21,758 $ 3,991
Production costs ........... (3,693) (3,693) - (4,333) (4,333) - (5,858) (5,193) (665)
Depreciation, depletion,
and amortization ......... (3,777) (3,777) - (5,313) (5,313) - (9,103) (7,695) (1,408)
General and administrative . (202) (202) - (261) (261) - (483) (401) (82)
Income taxes ............... - - - - - - (148) - (148)
--------- --------- -------- ---------- --------- ------- ---------- -------- --------

Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) .......... $ 3,442 $ 3,442 $ - $ 3,753 $ 3,753 $ - $ 10,157 $ 8,469 $ 1,688
========= ========= ======== ========= ======== ========= ======== ========= ========
Depletion rate per barrel
of oil equivalent ........ $ 4.35 $ 4.35 $ - $ 4.67 $ 4.67 $ - $ 5.12 $ 5.10 $ 5.29
========= ========= ======== ========= ======== ========= ======== ========= ========
</TABLE>

F-31
<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, 1994, 1995, and 1996. The
Company's management emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates have been prepared by
independent petroleum reserve engineers.
<TABLE>
<CAPTION>

Total United States Canada
-------------------------- ----------------------- --------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
------------- ---------- ------------- --------- -------------- ----------
(Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)

Proved developed and undeveloped reserves:
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1993 ........... 4,086 16,591 4,086 16,591 - -
Revisions of previous estimates ...... 854 5,034 854 5,034 - -
Extensions and discoveries ........... 2,268 15,062 2,268 15,062 - -
Purchase of minerals in place ........ 2,417 33,288 2,417 33,288 - -
Production ........................... (469) (2,393) (469) (2,393) - -
Sale of minerals in place ............ - (3) - (3) - -
---------- --------- ---------- -------- ----------- ----------
Balance at December 31, 1994 ........... 9,156 67,579 9,156 67,579 - -
Revisions of previous estimates ...... (1,328) (18,941) (1,328) (18,941) - -
Extensions and discoveries ........... 1,335 6,819 1,335 6,819 - -
Purchase of minerals in place ........ 214 2,889 214 2,889 - -
Production ........................... (544) (3,553) (544) (3,553) - -
Sale of minerals in place ............ (566) (224) (566) (224) - -
------------ -------------- ------------- --------------------- ---------------
Balance at December 31, 1995 ........... 8,267 54,569 8,267 54,569 - -
Revisions of previous estimates ...... 680 (2,561) 680 (2,561) - -
Extensions and discoveries ........... 1,752 10,194 1,746 10,060 6 134
Purchase of minerals in place ........ 8,062 121,408 6,694 65,135 1,368 56,273
Production ........................... (724) (6,350) (670) (5,042) (54) (1,308)
Sale of minerals in place ............ (2) - (2) - - -
---------- --------- ---------- -------- ----------- ----------

Balance at December 31, 1996 ........... 18,035 177,260 16,715 122,161 1,320 (1) 55,099
========== ========= ========== ======== =========== ==========
</TABLE>

(1) Includes 120,400 barrels of crude oil reserves owned by Cascade of which
57,600 barrels are applicable to the minority interest's share of these
reserves.

F-32
<PAGE>

Estimated Quantities of Proved Oil and Gas Reserves (continued)
<TABLE>
<CAPTION>

Proved developed reserves:
<S> <C> <C> <C> <C> <C> <C>
December 31, 1994 .................... 5,701 48,973 5,701 48,973 - -
========== ========= ========== ======== =========== ==========

December 31, 1995 .................... 6,000 44,026 6,000 44,026 - -
========== ========= ========== ======== =========== ==========

December 31, 1996 .................... 14,961 157,660 13,641 103,639 1,320 54,021
========== ========= ========== ======== =========== ==========
</TABLE>

The significant upward revision in 1994 of previous liquid hydrocarbons
and natural gas was due principally to increased estimates of recoverable
reserves in existing wells as a result of drilling and workover success in 1994,
combined with the completion of geological engineering studies on several major
fields.

The significant downward revision in 1995 of previous liquid
hydrocarbons and natural gas was due principally to decreased estimates of
recoverable reserves in existing wells related to disappointing drilling results
principally in the East White Point Field, resulting in reclassification of
proved undeveloped reserves to probable reserves.

F-33
<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 are presented in
accordance with Statement of Financial Accounting Standards 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, 1996, 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 Company's basis in the associated proved
crude oil and natural gas properties, less 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-34
<PAGE>

Set forth below is the Standardized Measure relating to proved oil and
gas reserves for:
<TABLE>
<CAPTION>

Years Ended December 31
------------------------------------------------------------------------------------------------
1994 1995 1996
--------------------------------- --------- ------------------- --------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
----------- --------- -------- --------- --------- -------- ----------- -------- ----------
(In thousands)

<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Future cash inflows .......... $ 238,028 $ 238,028 $ - $ 243,969 $ 243,969 $ - $ 1,009,420 $ 824,776 $184,644
Future production and
development costs .......... (84,552) (84,552) - (79,910) (79,910) - (251,749) (201,498) (50,251)
Future income tax expense .... (26,542) (26,542) - (28,015) (28,015) - (207,834) (157,508) (50,326)
----------- --------- -------- --------- --------- -------- ----------- -------- ---------
Future net cash flows ........ 126,934 126,934 - 136,044 136,044 - 549,837 465,770 84,067
Discount ..................... (49,241) (49,241) - (48,884) (48,884) - (220,016) (193,221) (26,795)
----------- --------- -------- --------- --------- -------- ----------- -------- ---------
Standardized Measure of
discounted future net cash
relating to proved reserves $ 77,693 $ 77,693 $ - $ 87,160 $ 87,160 $ - $ 329,821 $ 272,549 $ 57,272
========== ========= ======== ========= ========= ======== =========== ========== ========

</TABLE>

F-35
<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:

Year Ended December 31
------------------------------------
1994 1995 1996
--------- ----------- -----------
(In thousands)

Standardized Measure, beginning
of year ............................... $ 32,929 $ 77,693 $ 87,160
Sales and transfers of oil and gas
produced, net of production costs ..... (7,421) (9,351) (19,887)
Net changes in prices and development and
production costs from prior year ...... 2,450 22,560 65,917
Extensions, discoveries, and improved
recovery, less related costs .......... 13,509 13,475 30,699
Purchases of minerals in place .......... 29,163 3,867 244,930
Sales of minerals in place .............. (2) (3,355) (24)
Revision of previous quantity estimates . 7,346 (24,937) 2,257
Change in future income tax expense ..... 5,804 382 (87,393)
Other ................................... (9,377) (943) (2,554)
Accretion of discount ................... 3,292 7,769 8,716
--------- --------- ---------
Standardized Measure, end of year ..... $ 77,693 $ 87,160 $ 329,821
========= ========= =========

F-36

<PAGE>

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to the signed on its
behalf by the undersigned, thereunto duly authorized.

ABRAXAS PETROLEUM CORPORATION

By: /s/ Robert L.G. Watson By: /s/ Chris Willford
-------------------------- ----------------------------
Robert L.G. Watson, Chris Williford, Executive
President and Principal Vice President and
Executive Officer Principal Financial and
Accounting Officer
DATED:

Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.

Signature Name and Title Date
---------- ---------------- --------
/s/ Robert L.G. Watson Chairman of the Board, President 3/28/97
- ---------------------------- (Principal Executive Officer)
Robert L.G. Watson and Director

/s/ Chris Williford Exec. Vice President and 3/28/97
- ---------------------------- Treasurer (Principal Financial
Chris Williford and Accounting Officer) and
Director

/s/ Franklin Burke Director 3/28/97
- ----------------------------
Franklin Burke

/s/ Robert D. Gershen Director 3/28/97
- ----------------------------
Robert D. Gershen

/s/ Richard M. Kleberg, III Director 3/28/97
- ----------------------------
Richard M. Kleberg, III

/s/ Harold Carter Director 3/28/97
- ----------------------------
Harold Carter

/s/ James C. Phelps Director 3/28/97
- ----------------------------
James C. Phelps

/s/ Paul A. Powell, Jr. Director 3/28/97
- ----------------------------
Paul A. Powell, Jr.

/s/ Richard M. Riggs Director 3/28/97
- ----------------------------
Richard M. Riggs

<PAGE>

Exhibit (11) - Statement Re:
Computation of Earnings Per Share

Year Months Ended
December 31

1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Primary:
Average shares outstanding 5,757,105 4,635,412 4,309,878
Net effect of dilutive stock options
and warrants based on the treasury stock
method using average market price 24,277 -- (1) -- (1)

Assumed issuance under existing
Contingent Value Rights agreement 1,013,060 -- (1) -- (1)
---------- ----------- ----------
Totals 6,794,442 4,635,412 4,309,878
Net Income (loss) $1,147,525 $(1,574,428) $(2,278,000)
Per share amount $ .17 $ (.34) $ (.60)

Fully diluted: 5,757,105 4,635,412 4,309,878
Average shares outstanding
Net effect of dilutive stock options
and warranrsbased on the Treasury Stock
method using the year-end market price 176,569 -- (1) -- (1)
Assumed issuance under existing Contingent
Value Rights agreement 1,013,060 -- (1) -- (1)
Assumed conversion of convertible preferred
stock -- (1) -- (1) -- (1)
---------- ----------- -----------

Totals 6,946,734 4,635,412 4,309,878
Net income (loss) $1,147,525 $(1,574,428) $(2,578,000)
Per share amount $ .17 $ (.34) $ (.60)

</TABLE>

(1) Net effect if stick options, and warrants and convertible preferred stock
are not included because the effect is antidilutive.

<PAGE>

Exhibit 23.1

Consent of Independent Auditors

We consent to the incorporation by reference in the Registration
Statements (Form S-8 No. 33-48932) pertaining to Abraxas Petroleum Corporation
1984 Non-Qualified Stock Option Plan; (Form S-8 No. 33-48934) pertaining to
Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan; (Form S-8 No.
33-72268) pertaining to the Abraxas Petroleum Corporation 1993 Key Contribution
Stock Option Plan; (Form S-8 No. 33-81416) pertaining to the Abraxas Petroleum
Corporation Restricted Share Plan for Directors; (Form S-8 No. 33-81418)
pertaining to Abraxas Petroleum Corporation 1994 Long Term Incentive Plan; (Form
S-8 No. 333-17375) pertaining to the Abraxas Petroleum Corporation Director
Stock Option Plan; (Form S-8 No. 333-17377) pertaining to the Abraxas Petroleum
Corporation 401 (K) Profit Sharing Plan; and (Form S-3 No. 333-398) of Abraxas
Petroleum Corporation and the related Prospectus of our report dated March 21,
1997, with respect to the consolidated financial statements of Abraxas Petroleum
Corporation and subsidiaries included in this Annual Report (Form 10-K) for the
year ended December 31, 1996.

Ernst & Young LLP

San Antonio, Tx
March 21, 1997

<PAGE>

Exhibit 23.2

Consent of independent, third party, Petroleum Engineers

Degolyer and MacNaughton
One Energy Square
Dallas, TX 75206

March 25, 1996

Abraxas Petroleum Corporation
500 N. Loop 1604 E., Suite 100
San Antonio, TX 78232

Gentlemen:

We hereby consent to the incorporation in your Annual Report on Form
10-K of the references to DeGolyer and MacNaughton in the "Reserves Information"
section on page 20 and to the use by reference of information contained in our
"Appraisal Report as of December 31, 1996 on Certain Interests owned by Abraxas
Petroleum Corporation US Properties," in our "Appraisal Report as of December
31, 1996 on Certain Interests owned by Abraxas Petroleum Corporation Canadian
Properties," and in our "Appraisal Report as of December 31, 1996 on Certain
Interests owned by Abraxas Petroleum Corporation All Properties," provided,
however, that since the crude oil and condensate reserves estimates, as of
December 31, 1996, set forth in these Reports have been combined with reserves
estimates of other petroleum consultants, we are necessarily unable to verify
the accuracy of the crude oil and condensate reserves values contained in the
aforementioned Annual Report.

Very truly yours,

DeGolyer and MacNaughton

<ARTICLE> 5

<S> <C>
<MULTIPLIER> 1000
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 8290
<SECURITIES> 0
<RECEIVABLES> 14420
<ALLOWANCES> 36
<INVENTORY> 451
<CURRENT-ASSETS> 23312
<PP&E> 310043
<DEPRECIATION> 38653
<TOTAL-ASSETS> 304842
<CURRENT-LIABILITIES> 16879
<BONDS> 215000
0
0
<COMMON> 58
<OTHER-SE> 35598
<TOTAL-LIABILITY-AND-EQUITY> 304842
<SALES> 26349
<TOTAL-REVENUES> 26653
<CGS> 0
<TOTAL-COSTS> 17827
<OTHER-EXPENSES> 399
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 6241
<INCOME-PRETAX> 2186
<INCOME-TAX> 0
<INCOME-CONTINUING> 1940
<DISCONTINUED> 0
<EXTRAORDINARY> (427)
<CHANGES> 0
<NET-INCOME> 1147
<EPS-PRIMARY> 0.17
<EPS-DILUTED> 0.17

</TABLE>