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                                  UNITED STATES

                        SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                             --------------------
                                   FORM 10-K

              [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

                                       or

              [ ]   Transition Report Pursuant to Section 13 or 15(d)
                        of the Securities Exchange Act of 1934
                   For the transition period from _______ to _______

                          COMMISSION FILE NO. 0-21411

                             --------------------

                             COSTILLA ENERGY, INC.
             (Exact name of registrant as specified in its charter)

                             --------------------

            DELAWARE                                       75-2658940
   (State or other jurisdiction of                      (I.R.S. Employer
    incorporation or organization)                     Identification No.)

            400 WEST ILLINOIS, SUITE 1000 MIDLAND, TEXAS  79701
           (Address of principal executive offices)    (Zip code)

                                (915) 683-3092
            (Registrant's telephone number, including area code)

    Securities registered pursuant to Section 12(b) of the Act:  None

        Securities registered pursuant to Section 12(g) of the Act:

    COMMON STOCK, $0.10 PAR VALUE              10 1/4% SENIOR NOTES DUE 2006
         (Title of Class)                             (Title of Class)

                             --------------------

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         NO   X*
                                -------    -------

     *The Registrant's Form 8-A was declared effective with the Securities 
and Exchange Commission on October 2, 1996.

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 Common Stock held by non-affiliates, based 
upon the last sale price as quoted on the Nasdaq Stock Market's National 
Market of $13.00 per share on March 21, 1997, was $79,887,340.

Number of shares of Common Stock outstanding as of March 21, 1997 ... 10,476,500

DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form 10-K will be included in 
the registrant's definitive Proxy Statement, which will be filed with the 
Commission not later than April 30, 1997 and which is incorporated herein by 
reference.

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                            COSTILLA ENERGY, INC.

                              TABLE OF CONTENTS

                                                                         PAGE
                                                                         ----
PART I.

Item 1.      Business.                                                     3

Item 2.      Properties.                                                  10

Item 3.      Legal Proceedings.                                           18

Item 4.      Submission of Matters to a Vote of Security Holders.         18

PART II.

Item 5.      Market for the Registrant's Common Equity and
             Related Stockholder Matters.                                 19

Item 6.      Selected Financial Data.                                     20

Item 7.      Management's Discussion and Analysis of Financial
             Condition and Results of Operations.                         21

Item 8.      Financial Statements and Supplementary Data.                 26

Item 9.      Changes in and Disagreements with Accountants on
             Accounting and Financial Disclosure.                         26

PART III.

Item 10.     Directors and Executive Officers of the Registrant.          27

Item 11.     Executive Compensation.                                      27

Item 12.     Security Ownership of Certain Beneficial Owners 
             and Management.                                              27

Item 13.     Certain Relationships and Related Transactions.              27

PART IV.

Item 14.     Exhibits, Financial Statement Schedules and Reports on
             Form 8-K.                                                    28

SIGNATURES                                                                30



                                      2

<PAGE>

                                    PART I


              SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Form 10-K under "Item 1. Business," "Item 3. Legal 
Proceedings," "Item 7. Management's Discussion and Analysis of Financial 
Condition and Results of Operations," and elsewhere in this Form 10-K 
constitute "forward-looking statements" within the meaning of the Private 
Securities Litigation Reform Act of 1995 (the "Reform Act").  Such 
forward-looking statements involve known and unknown risks, uncertainties, 
and other factors which may cause the actual results, performance, or 
achievements of Costilla Energy, Inc. ("Costilla" or the "Company") to be 
materially different from any future results, performance, or achievements 
expressed or implied by such forward-looking statements.  Such factors 
include, among others, the following:  the volatility of oil and gas prices, 
the Company's drilling results and ability to replace oil and gas reserves, 
the availability of capital resources, the reliance upon estimates of proved 
reserves, operating hazards and uninsured risks, competition, government 
regulation, and the ability of the Company to implement its business 
strategy, and other factors referenced in the Company's recent prospectus for 
its initial public offering of common stock.

ITEM 1.  BUSINESS.

Special Note:  Certain statements set forth below under this caption 
constitute "forward-looking statements" within the meaning of the Reform Act. 
See "Special Note Regarding Forward-Looking Statements" for additional 
factors relating to such statements.

GENERAL

Costilla Energy, Inc. ("Costilla" or the "Company") is an independent energy 
company that is engaged in the exploration, exploitation, development, and 
acquisition of oil and gas properties.  The Company's primary operations are 
in the Permian Basin area of Texas and New Mexico, the Gulf Coast (onshore) 
and the Rocky Mountain regions.  In 1996 the Company acquired an interest in 
an entity which has a concession for the development of mineral interests in 
the Republic of Moldova, in Eastern Europe.  

The Company's predecessor began operating in 1988 with the strategy of 
acquiring and exploiting undervalued oil and gas properties, and at December 
31, 1992 had net proved reserves of 4.7 MMBOE.  Since January 1, 1993, the 
Company has successfully closed seven transactions for an aggregate purchase 
price of approximately $101 million.  As of January 1, 1997, the Company had 
total estimated net proved reserves of 17.0 Mmbbls of oil and 120.3 Bcf of 
gas, aggregating 37.0 MMBOE, with a PV-10 Value of approximately $311.8 
million, all of which has been calculated pursuant to the requirements of the 
Securities and Exchange Commission.  The Company also has a substantial 
undeveloped acreage position consisting of  242,541 gross (147,742 net) acres 
at December 31, 1996.  The Company has identified in excess of 200 drilling 
locations of which 88 are included in its proved reserves.

Costilla has in-house exploration expertise which uses 3-D seismic technology 
as a primary tool to identify drilling opportunities and has experienced high 
rates of success in each of its first two major 3-D seismic drilling programs.
Since 1994, the Company has drilled 41wells based on these 3-D surveys, 36 of 
which have been productive. The Company has completed two additional 3-D 
surveys in 1996 on one of these acreage blocks.  The Company currently plans 
to drill approximately 48 wells in 1997 based on its 3-D surveys.

Since 1993, Costilla has generated significant growth in reserves and 
production.  The Company increased its estimated proved reserves from 6.0 
MMBOE at January 1, 1994 to 37.0 MMBOE at January 1, 1997 representing a 
compound annual growth rate of 83%.  This reserve growth has been achieved at 
an average All-In Finding Cost of $3.68 per BOE over such period, a level 
which the Company believes is lower than industry averages.  Concurrently, 
the Company increased its average net daily production from 827 BOE for the 
year ended December 31, 1993 to 8,907 BOE for the year ended December 31, 
1996, representing a compound annual growth rate of 121%.  The Company's 
production rate at December 31, 1996 was approximately 12,400 BOEPD.  

Oil and gas terms used herein are defined under "-Definition of Certain Oil 
and Gas Terms".


                                      3

<PAGE>

CORPORATE REORGANIZATION

Costilla was incorporated in Delaware in June 1996 primarily to consolidate 
and continue the activities previously conducted by Costilla Energy, L.L.C., 
a Texas limited liability company (the "LLC").  Costilla was formed for the 
purpose of conducting a $60 million initial public offering of common stock 
and a $100 million senior notes offering (the "Offerings"), which  Offerings 
were completed in early October 1996.

The following is a description of sources and uses of proceeds from the 
Offerings (in millions):

SOURCES:

   Notes Offering . . . . . . . . . . . . . . . . . . . . . .  $  100.0 
   Common Stock Offering. . . . . . . . . . . . . . . . . . .      65.9 (a)
                                                               --------
                                                               $  165.9
                                                               --------
                                                               --------

USES:

   Refinance Existing Debt. . . . . . . . . . . . . . . . . .  $  125.8 
   Redeem membership interests in the L.L.C.  . . . . . . . .      15.5 
   Distributions to individual members to pay estimated 
    income tax liability of such members in the L.L.C.  . . .       3.4 
   Pro rata distribution to remaining member in the L.L.C.. .       0.8 
   Purchase of stock and assets of affiliated companies . . .       0.7 
   Working capital. . . . . . . . . . . . . . . . . . . . . .      10.7 
   Estimated fees, commissions, underwriting discounts and 
    expenses related to the Offerings . . . . . . . . . . . .       9.0 
                                                               --------
                                                               $  165.9 
                                                               --------
                                                               --------
-------------------
    (a)  Includes 475,000 shares of the underwriter's over-allotment exercised
         subsequent to the closing of the common stock offering.

The Company's executive offices are located at 400 West Illinois, Suite 1000, 
Midland, Texas, 79701 (mailing address P.O. Box 10369, Midland, Texas 79702) 
and its telephone  number is (915) 683-3092.

BUSINESS STRATEGY

The Company's strategy is to increase its oil and gas reserves, production 
and cash flow from operations through a two-pronged approach which combines 
an active exploration program using 3-D seismic and other technological 
advances with the acquisition and exploitation of producing properties.  The 
Company seeks to reduce its operating and commodity risks by holding a 
geographically diverse portfolio of properties, the reserves attributable to 
which are approximately balanced between oil and gas.  The Company also seeks 
to manage the elements of its business strategy through the operation of a 
significant portion of its properties, the use of a rate of return analysis 
and the direct marketing and hedging of its oil and gas production.  The 
elements of the Company's strategy may be further described as follows:

     -        EXPLORATION EFFORTS.  The Company uses extensive geological
         and geophysical analysis to carefully focus its 3-D seismic surveys.
         This focus allows the Company to successfully direct the size and 
         scope of its exploration program in order to improve the likelihood
         of success while managing overall exploration costs.  The Company's
         exploration efforts are concentrated currently in known producing 
         regions.  The Company's 1997 capital budget for exploration activities
         is $7.2 million, which includes the drilling of 26 exploratory wells.
         In addition, Costilla has $5.2 million budgeted for the acquisition 
         of undeveloped acreage and seismic projects.


                                      4

<PAGE>

     -        EXPLOITATION ACTIVITIES.  The Company is actively pursuing
         numerous exploitation opportunities within its existing properties, 
         including areas where no proved reserves are currently assigned.  
         Exploitation activities currently in progress include the drilling 
         of development wells, recompletions, workovers, infill and horizontal
         drilling, a secondary recovery project and a carbon dioxide flood.  
         The Company's 1997 capital budget for such activities is $13.6 million,
         which includes the drilling of 36 development wells.
    
     -        PROPERTY ACQUISITIONS.  The Company seeks to acquire producing 
         properties where it has identified opportunities to increase 
         production and reserves through both exploitation and exploration 
         activities.  The Company has increased the value of its acquisitions 
         by aggressively managing the operations of existing proved properties
         and by successfully identifying and developing previously unproved 
         reserves on acquired acreage.  The Company seeks to acquire reserves 
         which will fit its existing portfolio, are generally not being actively
         marketed and where a negotiated sale would be the method of purchase. 
         The Company does not rely on major oil company divestitures or property
         auctions.
    
     -       PROPERTY DIVERSIFICATION.  The Company holds a portfolio of oil and
         gas properties located in the Permian Basin, the Gulf Coast and the 
         Rocky Mountain regions.  The Company believes that by conducting its 
         activities in distinct regions it is able to reduce commodity price 
         and other operational risks.  The Company's Moldovan interest is an 
         extension of this strategy and can be characterized by low initial 
         costs, additional reserve potential and the availability of technical 
         data that may be further developed by the Company.
    
     -       CONTROL OF OPERATIONS.  The Company prefers to operate and own
         the majority working interest in its properties.  This allows the
         Company greater control over future development, drilling, completing
         and operating costs and marketing of production.  At January 1, 1997,
         the Company operated wells constituting approximately 74% of its 
         total PV-10 Value.

SIGNIFICANT ACQUISITIONS

1995 ACQUISITION.  In a $46.6 million acquisition completed in June 1995, the 
Company acquired a group of oil and gas properties located in the Permian 
Basin, Gulf Coast and Rocky Mountain regions.  At the date of acquisition, 
the net proved reserves included 7.1 Mmbbls of oil and 44.1 Bcf of gas,  
aggregating 14.4 MMBOE.  From the date of acquisition until December 31, 
1996, the Company produced 2.8 MMBOE from the acquired properties and sold a 
portion of the acquired properties for approximately $3.6 million.  At 
January 1, 1997, the net proved reserves of the remaining properties were 
13.9 MMBOE.  The acquired properties also included 103,010 gross (93,787 net) 
undeveloped acres.

1996 ACQUISITION.  In June 1996, the Company acquired a group of oil and gas 
properties located primarily in the Permian Basin and Gulf Coast regions for 
an adjusted purchase price of approximately $38.7 million.  This acquisition 
included properties with net proved reserves at April 1, 1996 of 5.0 Mmbbls 
of oil and 33.5 Bcf of gas, aggregating 10.6 MMBOE.  The acquired properties 
also included 42,855 gross (16,646 net) undeveloped acres and a pipeline 
located in Pennsylvania, which was sold on December 31, 1996 for $3.3 million.

RECENT DEVELOPMENTS

On December 31, 1996, the Company closed the sale of all of the capital stock 
of a wholly owned subsidiary,  which owned a 120 mile gas transportation 
pipeline in southwestern Pennsylvania, for net proceeds of $3.3 million.  The 
pipeline was acquired through the 1996 Acquisition, was regarded as a 
non-strategic asset to the Company's business and had been held for resale.

On December 31, 1996 the Company also closed the sale of substantially all of 
the assets of another wholly owned subsidiary, for net proceeds of 
approximately $3.0 million.  The remaining assets of the subsidiary are held 
by the Company.


                                      5

<PAGE>

In 1996, the Company purchased a 40.5% membership interest in Republic Gas 
Partners, L.L.C., a Delaware limited liability company ("Republic"), for 
approximately $1,020,000.  Republic owns and operates gas pipelines and 
associated facilities in Louisiana.In March 1997, the Company sold its 
investment in Republic for an amount equal to its original cost, plus 
interest from the date of purchase.

COMPETITION AND MARKETS

Competition in all areas of the Company's operations is intense. Major and 
independent oil and gas companies and oil and gas syndicates actively bid for 
desirable oil and gas properties, as well as for the equipment and labor 
required to operate and develop such properties. A number of the Company's 
competitors have financial resources and acquisition, exploration and 
development budgets that are substantially greater than those of the Company, 
which may adversely affect the Company's ability to compete with these 
companies.  Many of the Company's competitors have been engaged in the energy 
business for a much longer time than the Company.  Such companies may be able 
to pay more for productive oil and gas properties and exploratory prospects 
and to define, evaluate, bid for and purchase a greater number of properties 
and prospects than the Company's financial or human resources permit.  The 
Company's ability to acquire additional properties and to discover reserves 
in the future will be dependent on its ability to evaluate and select 
suitable properties and to consummate transactions in a highly competitive 
environment.

The market for oil, gas and natural gas liquids produced by the Company 
depends on factors beyond its control, including domestic and foreign 
political conditions, the overall level of supply of and demand for oil, gas 
and natural gas liquids, the price of imports of oil and gas, weather 
conditions, the price and availability of alternative fuels, the proximity 
and capacity of gas pipelines and other transportation facilities and overall 
economic conditions.  The oil and gas industry as a whole also competes with 
other industries in supplying the energy and fuel requirements of industrial, 
commercial and individual consumers.

REGULATION

The Company's oil and gas exploration, production and related operations are 
subject to extensive rules and regulations promulgated by federal, state and 
local agencies.  Failure to comply with such rules and regulations can result 
in substantial penalties.  The regulatory burden on the oil and gas industry 
increases the Company's cost of doing business and affects its 
profitability.  Because such rules and regulations are frequently amended or 
reinterpreted, the Company is unable to predict the future cost or impact of 
complying with such laws.

The State of Texas and many other states require permits for drilling 
operations, drilling bonds and reports concerning operations and impose other 
requirements relating to the exploration and production of oil and gas.  Such 
states also have statutes or regulations addressing conservation matters, 
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and 
the regulation of spacing, plugging and abandonment of such wells.  The 
statutes and regulations of certain states limit the rate at which oil and 
gas can be produced from the Company's properties.

The Federal Energy Regulatory Commission ("FERC") regulates interstate 
natural gas transportation rates and service conditions.  Such regulation 
affects the marketing of gas produced by the Company and the revenues 
received by the Company for sales of such production. Since the mid-1980s, 
FERC Orders have fundamentally restructured interstate pipeline sales and 
transportation services, including the unbundling by interstate pipelines of 
the sales, transportation, storage and other components of the city-gate 
sales services such pipelines previously performed.  These regulatory measures 
may ultimately enhance the Company's ability to market and transport its gas, 
although it may also subject the Company to greater competition, more 
restrictive pipeline imbalance tolerances and greater penalties if those 
tolerances are violated.

The FERC has recently announced several important transportation-related 
policy statements and proposed rule changes, including policy statements on 
how interstate natural gas pipelines can recover the cost of new pipeline 
facilities and policy statements on alternatives to its traditional 
cost-of-service ratemaking methodology (including criteria to be used in 
evaluating proposals to charge market-based rates for the transportation of 
natural gas).  In addition, the FERC is reconsidering its regulations regarding 
releases of firm interstate natural gas pipeline capacity.  While the Company 
cannot predict exactly how FERC actions might impact the Company's natural 
gas sales, it 


                                      6

<PAGE>

does not believe it will be treated materially differently than other natural 
gas producers and marketers with which it completes.

ENVIRONMENTAL MATTERS

Operations of the Company are subject to numerous and constantly changing 
federal, state and local laws and regulations governing the discharge of 
materials into the environment or otherwise relating to environmental 
protection.  These laws and regulations may require the acquisition of certain 
permits, restrict or prohibit the types, quantities and concentration of 
substances that can be released into the environment in connection with 
drilling and production, restrict or prohibit drilling activities that could 
impact wetlands, endangered or threatened species or other protected natural 
resources and impose substantial liabilities for pollution resulting form the 
Company's operations.  Such laws and regulations may substantially increase the 
cost of exploring for, developing or producingoil and gas and may prevent or 
delay the commencement or continuation of a given project. In the opinion of 
the Company's management, the Company is in substantial compliance with 
current applicable environmental laws and regulations, and the cost of 
compliance with such laws and regulations has not been material and is not 
expected to be material during the next fiscal year.  Nevertheless, changes in 
existing environmental laws and regulations or in interpretations thereof 
could have a significant impact on the operating costs of the Company, as 
well as the oil and gas industry in general.  For instance, legislation has 
been proposed in congress from time to time that would reclassify certain oil 
and gas production wastes as "hazardous wastes," which reclassification would 
make exploration and production wastes subject to much more stringent 
handling, disposal and clean-up requirements. State initiatives to further 
regulate the disposal of oil and gas wastes and naturally occurring 
radioactive materials are also pending in certain states, including Texas, 
and these various initiatives could have a similar impact on the Company.

The Comprehensive Environmental Response, Compensation, and Liability Act 
("CERCLA"), also know as the "Superfund" law, imposes liability, without 
regard to fault or the legality of the original conduct, on certain classes 
of persons that are considered to have contributed to the release of a 
"hazardous substance" into the environment.  These persons include the owner or 
operator of the disposal site or the site where the release occurred and 
companies that disposed or arranged for the disposal of the hazardous 
substances found at the site.  Persons who are or were responsible for releases 
of hazardous substances found at the site and persons who are or were 
responsible for releases of hazardous substances under CERCLA may be subject 
to joint and several liability for the costs of cleaning up the hazardous 
substances that have been released into the environment and for damages to 
natural resources, and it is not uncommon for neighboring landowners and 
other third parties to file claims for personal injury and property damage 
allegedly caused by the hazardous substances released into the 
environment.  The Company is able to control directly the operation of only 
those wells with respect to which its acts as operator.  Notwithstanding the 
Company's lack of control over wells operated by others, the failure of the 
operator to comply with applicable environmental regulations may, in certain 
circumstances, be attributed to the Company.  The Company has no material 
commitments for capital expenditures to comply with existing environmental 
requirements.

EMPLOYEES

At December 31, 1996, the Company had 114 full time employees.  None of the 
Company's employees is subject to a collective bargaining agreement.  The 
Company considers its relations with its employees to be good.


                                      7

<PAGE>
                                       
                    DEFINITION OF CERTAIN OIL AND GAS TERMS
                                        

The terms defined in this section are used throughout this Form 10-K.

ALL-IN FINDING COSTS.  The amount of total capital expenditures, including 
acquisition costs, and exploration and abandonment costs for oil and gas 
activities, divided by the amount of proved reserves (expressed in BOE) added 
during the specified period (including the effect on proved reserves of 
reserve revisions).

BBL.  One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in 
reference to crude oil or other liquid hydrocarbons.

BCF.  One billion cubic feet.

BOE.  Equivalent barrels of oil.  In reference to natural gas, natural gas 
equivalents are determined using the ratio of six MCF of natural gas to one 
Bbl of crude oil, condensate or natural gas liquids.

BTU.  One British thermal unit.  The quantity of heat required to raise the 
temperature of one pound of water one degree Fahrenheit.

DEVELOPED ACREAGE.  The number of acres which are allocated or assignable to 
producing wells or wells capable of production.

DEVELOPMENT WELL.  A well drilled within the proved area of an oil or gas 
reservoir to the depth of a stratigraphic horizon know to be productive.

DRY WELL.  A well found to be incapable of producing either oil or gas in 
sufficient quantifies to justify completion of an oil or gas well.

EXPLORATORY WELL.  A well drilled to find and produce oil or gas in an 
unproved area, to find a new reservoir in a field previously found to be 
productive of oil or gas in another reservoir, or to extend a known reservoir.

GROSS ACRES OR GROSS WELLS.  The total acres or wells, as the case may be, in 
which a working interest is owned.

MBBL.  One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE.  One thousand barrels of oil equivalent.

MMBOE.  One million barrels of oil equivalent.

MMBBLS.  One million barrels of crude oil or other liquid hydrocarbons.

MMBTU.  One million Btu's.

MCF.  One thousand cubic feet.

MMCF.  One million cubic feet.

NET ACRES OR NET WELLS.  The sum of the fractional working interests owned in 
gross acres or gross wells.

PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES OR PV-10 VALUE.  The present 
value of estimated future net revenues is an estimate of future net revenues 
from a property at its acquisition date, at a specified date, after deducting 
production and ad valorem taxes, future capital costs and operating expenses, 
but before deducting federal income taxes.  The future net revenues have been 
discounted at an annual rate of 10% to determine their "present value."  The 
present value is shown to indicate the effect of time on the value of the 
revenue stream and 



                                      8

<PAGE>
                                       
should not be construed as being the fair market value of the properties.  
Estimates have been made using constant oil and natural gas prices and 
operating costs at the specified date.

PRODUCTIVE WELL.  A well that is producing oil or gas that is capable of 
production.

PROVED DEVELOPED RESERVES.  Reserves that can be expected to be recovered 
through existing wells with existing equipment and operating methods.

PROVED RESERVES.  The estimated quantities of crude oil, natural gas and 
natural gas liquids which geological and engineering data demonstrate with 
reasonable certainty to be recoverable in future years from known reservoirs 
under existing economic and operating conditions.

PROVED UNDEVELOPED RESERVES.  Reserves that are expected to be recovered from 
new wells on undrilled acreage, or from existing wells where a relatively 
major expenditure is required for recompletion.

ROYALTY INTEREST.  An interest in an oil and gas property entitling the owner 
to a share of oil and gas production free of costs of production.

3-D SEISMIC.  Advanced technology method of detecting accumulations of 
hydrocarbons identified by the collection and measurement of the intensity 
and timing of sound waves transmitted into the earth as they reflect back to 
the surface.

UNDEVELOPED ACREAGE.  Lease acreage 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 such acreage contains proved 
reserves.

WORKING INTEREST.  The cost bearing operating interest which gives the owner 
the right to drill, produce and conduct operating activities on the property 
and a share of production.










                                      9

<PAGE>
                                       
ITEM 2.  PROPERTIES.

PRINCIPAL PROPERTIES

The following table sets forth certain information, as of January 1, 1997, 
which relates to the principal oil and gas properties owned by the Company. 

                                            PROVED RESERVES
                           ---------------------------------------------------
                                                       TOTAL OIL    PERCENT OF
                           GROSS      OIL       GAS    EQUIVALENT   TOTAL OIL
                           WELLS    (MBBLS)    (MMCF)    (MBOE)     EQUIVALENT
                           -----    ------    -------  ----------   ----------
REGION
------

Permian Basin. . . . . . . 2,001     9,889     59,512    19,808        53.5%
Gulf Coast . . . . . . . .   932     2,189     37,149     8,381        22.6 
Rocky Mountain . . . . . .   249     4,124      5,742     5,081        13.7 
Other. . . . . . . . . . .   433       798     17,869     3,776        10.2 
                           -----    ------    -------    ------      ------
Total. . . . . . . . . . . 3,615    17,000    120,272    37,045      100.00%
                           -----    ------    -------    ------      ------
                           -----    ------    -------    ------      ------


PERMIAN BASIN.  At January 1, 1997, 53.5% of the Company's proved reserves 
were concentrated in the Permian Basin, an approximately 70-county region in 
West Texas and Southeast New Mexico.  The Company's production comes from 
well known formations such as the Spraberry, Canyon, Ellenberger and 
Devonian.  The majority of the Company's producing intervals in the Permian 
Basin range from 4,500 feet to 9,500 feet in depth.

The Company has several exploratory projects in the Permian Basin based 
primarily on 3-D seismic surveys.  The most significant include:

EDWARDS/MCELROY RANCH PROSPECT, ECTOR AND CRANE COUNTIES, TEXAS. Costilla has 
identified 81 drilling locations on the Company's 14,623 gross (7,165 net) 
acres in this prospect based on an approximate 80-square mile 3-D seismic 
project.  Through December 31, 1996, the Company drilled 15 wells on this 
prospect, of which 14 were successful resulting in three separate field 
discoveries.  In addition, these wells have confirmed the Strawn and Wolfcamp 
trends which were identified by the seismic project undertaken jointly with 
Texaco Exploration and Production Inc. ("Texaco").  The Company plans to 
drill 20 wells in this trend in 1997, two of which were in progress at 
December 31, 1996.  The Company's working interest in this prospect is 
approximately 49%.

Costilla and Texaco are also evaluating the development of a Queen Sand field 
identified from the Edwards/McElroy Ranch seismic program. The six producing 
wells at December 31, 1996 were producing an aggregate of approximately 50 
Bbls of oil per day.  A pilot waterflood has been commenced and is being 
evaluated for additional development. The drilling of one additional Queen 
Sand well is anticipated in 1997.

MACGYVER-GREEN ACRES PROSPECT, HOWARD COUNTY, TEXAS.  The Company has 
identified 53 locations in this prospect based on information derived from 
approximately 30 square miles of 3-D seismic data that the Company acquired 
on the area in 1994.  The Talbot Fuller well was the first well drilled by 
the Company on this prospect and was completed in the Canyon Lime formation 
at 8,600 feet in August 1994.  From completion to December 31, 1996, the well 
produced 72 MBbls of oil and 287 Mmcf of gas, and averaged 54 Bbls of oil per 
day and 625 Mcf of gas per day during December 1996. Of the 24 wells which 
have been drilled on this prospect, 20 are productive.  The 



                                      10

<PAGE>
                                       
Company intends to drill 20 additional wells during 1997 on its 10,041 gross 
(7,229 net) acres.  The Company's working interest in this prospect averages 
approximately 72%.

The following two 3-D programs currently being undertaken by the Company in 
the Permian Basin are expected to provide additional drilling locations:

WILSON RANCH 3-D PROJECT, PECOS COUNTY, TEXAS.  The Wilson Ranch is located 
in northeastern Pecos County, approximately 10 miles west of the Yates field. 
In 1996 the Company completed an approximate 17-square mile seismic survey 
on the project. The project presents several potential exploration targets, 
including the Queen, San Andres, Wolfcamp, Devonian and Ellenberger 
formations, found at depths ranging from 1,600 to 8,000 feet.  The Company 
has purchased a lease covering 3,750 gross acres on this 50,000 acre ranch.  
After acquiring the lease, the Company sold a portion of its interest in the 
lease to a major oil company, which left the Company with an approximately 
53% working interest.  The Company believes that there is significant 
potential in this area.

DAVAN UNIT 3-D PROJECT, STONEWALL COUNTY, TEXAS.  The Company has completed 
another 3-D seismic project to further develop the Company-operated Davan 
Unit.  The project involves a 3-D seismic evaluation of approximately 4,380 
gross acres adjacent to a Company-operated waterflood which has produced in 
excess of three Mmbbls of oil. The Company plans to drill four wells on this 
project during 1997.  The Company's working interest in this project is 100%.


An example of the Company's current exploitation efforts in the Permian Basin 
is:

WORLD FIELD, CROCKETT COUNTY, TEXAS.  This field was acquired in the 1996 
Acquisition.  It produces from the Grayburg formation at an average depth of 
2550 feet.  Discovered in 1926, it is one of the oldest and most prolific 
shallow fields in the Permian Basin. Costilla owns a 100% working interest in 
4,380 acres containing 87 existing wells.  At the time of acquisition, the 
field was producing approximately 480 Bbls of oil per day and 53,400 Bbls of 
water per day.  In December, 1996 the Company initiated a polymer treatment 
program to reduce water production and increase oil cut.  Thirteen treatments 
have been completed as of February 1997 resulting in oil production improving 
to approximately 650 Bbls of oil per day and water production dropping to 
approximately 43,500 Bbls of water per day.  Additionally, some submersible 
pumps have been replaced by progressing cavity pumps which are expected to be 
significantly less costly to operate.  A fieldwide study is underway to 
identify additional workover candidates as well as additional locations for 
development drilling.

GULF COAST.  At January 1, 1997, 22.6% of the Company's proved reserves were 
concentrated in the Gulf Coast region, on shore.  The Company's production in 
this region primarily comes from known formations such as Frio, Yegua, Austin 
Chalk and Wilcox.

The Company plans to use its expertise in aggressively developing 3-D 
opportunities on the extensive acreage position it holds in the region.  
Examples of such exploration projects in progress include:

SEALY PROSPECT, AUSTIN COUNTY, TEXAS.  The Sealy Field was acquired in the 
1995 Acquisition and currently consists of 10,982 gross and net acres.  The 
Wilcox formation in this field has produced over 66 Bcf of gas and there are 
subsurface indications of the presence of several fault blocks that lie 
untested.  The Company's working interest in this prospect is 100%.  The 
Company has acquired additional acreage in this prospect and plans to 
initiate a 3-D survey in 1997.

SOUTHWEST SPEAKS, LAVACA COUNTY, TEXAS.  This project was also acquired in 
the 1995 Acquisition and currently consists of 9,062 gross and net acres.  
Multiple producing horizons from shallow depths to below 14,000 feet have 
produced over 122 Bcf of gas from this highly faulted field.  A well has been 
completed in the Rainbow Wilcox sand on acreage adjoining Costilla's lease.  
A well, in which Costilla holds a 10% interest as a result of a farmout, is 



                                      11

<PAGE>
                                       
being completed on Costilla's lease.  The Company has commenced a 3-D survey 
in the Speaks area in the first quarter of 1997.  The Company's working 
interest in this prospect is 100%.

BORCHERS FIELD, LAVACA COUNTY, TEXAS.  This field was acquired by the Company 
in the 1996 Acquisition.  The property is on trend with the Speaks project 
and is also a highly faulted field providing opportunity for further 
development.  The Company's lease in the Borchers field area has produced 
over 21 Bcf of gas from two Wilcox sands.  Costilla has a 100% working 
interest in this field consisting of 1,322 gross and net acres.


Examples of exploitation activities in this region include:

PERSONVILLE, LIMESTONE COUNTY, TEXAS.  When this lease was acquired in the 
1995 Acquisition, it was producing 70 Mcf per day from one well. In the last 
half of 1996, the Company completed two 11,000 foot Cotton Valley wells which 
were collectively producing approximately 4.5 Mmcf per day in December 1996.  
A third well was completed in January 1997. The Company plans 14 additional 
wells in this area.  The Company is the operator and owns approximately 29% 
working interest in this 1,026 gross acre (298 net acre) lease.

AUSTIN CHALK, BRAZOS, BURLESON, FAYETTE AND LEE COUNTIES, TEXAS. Costilla 
acquired the majority of the working interest in nine gross Austin Chalk 
wells in the 1995 Acquisition and an additional 80 gross Austin Chalk wells 
were included in the 1996 Acquisition.  By mid-December 1996 the Company had 
worked over six wells via refracing and/or opening additional pay zones.  
Production has improved from 137 BOE per day to 325 BOE per day on those 
wells.  Additional increases in production are expected as frac loads are 
recovered.  Completion of the first two of seven planned horizontal wells in 
the Austin Chalk are the Patterson "G" 1-H, producing 326 barrels of oil and 
727,000 cubic feet of gas per day, and Mais-Kachtik 1-H, producing 364 
barrels of oil and 952,000 cubic feet of gas per day.  Costilla has 30,414 
gross (20,985 net) acres in the Austin Chalk area, and its working interest 
in this area averages approximately 69%.

ROCKY MOUNTAIN.  At January 1, 1997, 13.7% of the Company's proved reserves 
were concentrated in the Rocky Mountain region, which includes Montana, North 
Dakota, Wyoming, Colorado and Utah.

The Company has a number of opportunities in the Rocky Mountain region 
involving 3-D seismic surveys, exploratory drilling and exploitation 
activities.  Examples of each of these opportunities are:

OUTLOOK FIELD, SHERIDAN COUNTY, MONTANA.  The Company undertook its first 
Rocky Mountain 3-D seismic survey in the Outlook area to further develop the 
field.  Three drilling locations were identified from the data of which the 
first well has been drilled and completed as a producer.  Additional 
development is anticipated.  Costilla has 5,169 gross (1,292 net) acres in 
the Outlook prospect, and its working interest is approximately 25%. 

WATTENBERG FIELD, WELD COUNTY, COLORADO.   The Company operates 70 wells in 
the Wattenberg Field of the DJ Basin in northeast Colorado. During January, 
1997 the Company initiated an 11 well development program of which 7 wells 
have been completed at March 20, 1997, with initial producing rates averaging 
55 BOEPD per well.  An estimated 20 additional locations are drillable.  The 
Company owns an approximate 72% average working interest in 6,255 gross
(4,479 net) acres.


MARKETING ARRANGEMENTS

The Company utilizes an active marketing program for a portion of its crude 
oil production in order to enhance the net price it receives. The Company 
sells its crude oil production from operated properties in North Dakota, 
Montana and Wyoming, at the lease level to an oil transportation company for 
the posted price, plus an agreed upon bonus, with a corresponding agreement 
to repurchase this production at its delivery point (typically, Cushing, 
Oklahoma) for a price equal to the then posted price for West Texas 
Intermediate crude oil less an agreed upon deduction for transportation and 
quality differentials, if any between the repurchased crude oil and West 
Texas 



                                      12

<PAGE>
                                       
Intermediate crude oil.  The Company then employs a broker to resell its 
crude oil to end users (such as refineries) on a month-to-month basis.  The 
lease level sales and repurchase contracts are typically of six months 
durations.  With respect to its other operated oil production (primarily 
located in Texas), the Company employs a similar price enhancement strategy, 
although the repurchase feature is absent. Instead, the lease level purchaser 
resells the crude oil to end users at the delivery point for the account of 
the Company.  While these arrangements have the effect of  increasing the net 
price the Company receives for its crude oil, such arrangements do not have 
the effect of limiting the Company's exposure to movements in crude oil 
prices. The Company markets its gas production at the lease level pursuant to 
month-to-month contracts.  For the year ended December 31, 1996, one oil 
purchaser accounted for 11.2% of the Company's 1996 consolidated revenue.  
The Company does not anticipate any difficulty if it should have to replace 
any of the purchasers of its crude oil and natural gas.  


RISK MANAGEMENT

The Company typically employs a strategy of purchasing put options on a 
portion of its anticipated oil and gas production.  This strategy is designed 
to protect the Company from significant downward movements in commodity 
prices while preserving the benefit of rising prices.  The Company does not 
establish hedges in excess of its anticipated production. The Company's 
current position with regard to its 1997 commodity hedges is as follows:

OIL SALES.  As of December 31, 1996, the Company had purchased put options on 
6,536 barrels of oil per day for the calendar months June 1997 through 
October 1997 providing a floor price of $17.00 per barrel.  Additionally, the 
Company had purchased put options on 2,500 Bbls of oil per day for 1997 which 
provide a floor price of $16.00 per barrel and sold call options on 2,500 
barrels of oil per day for 1997 at $20.65 per barrel.  These put options 
provide downside protection on approximately 70% of the Company's estimated 
1997 oil production.

GAS SALES.  As of December 31, 1996, the Company had put options which 
provide a floor price of $1.65 per Mmbtu (approximately $1.82 per Mcf) for 
150,000 Mmbtu's per month of its gas production through October 1997.  In 
February 1997, the Company purchased put options which establish a floor 
price of $1.85 per Mmbtu (approximately $2.04 per Mcf) for 300,000 Mmbtu's 
per month of its gas production for the period April 1997 through October 
1997.  The put options currently in place represent approximately 25% of the 
Company's estimated gas production for 1997.  





                                      13
<PAGE>

OIL AND GAS RESERVES

The Company's estimated total proved and proved developed reserves of oil and 
gas as of January 1, 1997 were as follows:

                                             JANUARY 1, 1997
                                        --------------------------
                                          OIL       GAS
                                        (MBBLS)    (MMCF)    MBOE
                                        -------   -------   ------
     Proved developed producing . . . .  13,894    82,861   27,704 
     Proved developed non-
       producing. . . . . . . . . . . .     124     7,162    1,318 
     Proved undeveloped . . . . . . . .   2,982    30,249    8,023 
                                         ------   -------   ------
       Total proved . . . . . . . . . .  17,000   120,272   37,045 
                                         ------   -------   ------
                                         ------   -------   ------


The future net cash flows from the Company's estimated proved reserves as of 
January 1, 1997 were as follows: 

                                                        JANUARY 1, 1997
                                                        ---------------
                                                        (in thousands)
     Future net cash flows before 
       income taxes . . . . . . . . . . . . . . . . . .    $538,343 
     Future net cash flows before 
       income taxes, discounted 
       at 10% . . . . . . . . . . . . . . . . . . . . .    $311,803 


The reserve estimates at January 1, 1997 were prepared by Williamson 
Petroleum Consultants, Inc.

The reserve data set forth herein present estimates only.  In general, 
estimates of economically recoverable oil and gas reserves and of the future 
net revenues therefrom are based upon an number of variable factors and 
assumptions, such as historical production from the subject properties, the 
assumed effects of regulation by governmental agencies and assumptions 
concerning future oil and gas prices and future operating costs, all of which 
may vary considerably from actual results.  All such estimates are to some 
degree speculative, and classifications of reserves are only attempts to 
define the degree of speculation involved.  For these reasons, estimates of 
the economically recoverable oil and gas reserves attributable to any 
particular group of properties, classifications of such reserves based on 
risk of recovery and estimates of the future net revenues expected therefrom, 
prepared by different engineers or by the same engineers at different times 
may vary substantially.  The Company therefore emphasizes that the actual 
production, revenues, severance and excise taxes, development and operating 
expenditures with respect to its reserves will likely vary from such 
estimates, and such variances could be material.

Estimates with respect to proved reserves that may be developed and produced 
in the future are often based upon volumetric calculations and upon analogy 
to similar types of reserves rather than actual production history.  
Estimates based on these methods are generally less reliable than those based 
on actual production history. Subsequent evaluation of the same reserves 
based upon production history will result in variations, which may be 
substantial, in the estimated reserves.

In accordance with applicable requirements of the Securities and Exchange 
Commission (the "Commission"), the estimated discounted future net revenues 
from estimated proved reserves are based on prices and costs as of the date 
of the estimate unless such prices or costs are contractually determined at 
such date.  Actual future prices and costs may be materially higher or lower. 
Actual future net revenues also will be affected by factors such as actual 
production, supply and demand for oil and natural gas, curtailments or 
increases in consumption by natural gas purchasers, changes in governmental 
regulations or taxation and the impact of inflation on costs.



                                      14

<PAGE>

PRODUCTION VOLUMES, PRICES AND COSTS

The following table sets forth certain information regarding the Company's 
production volumes, average sales price and costs for the periods presented: 


                                           YEAR ENDED DECEMBER 31,
                                         --------------------------
                                          1996      1995      1994
                                         ------    ------    ------
Production:
  Oil (MBbls). . . . . . . . . . . . .    1,726       950       330 
  Gas (Mmcf) . . . . . . . . . . . . .    9,205     4,806     1,600 
  MBOE . . . . . . . . . . . . . . . .    3,260     1,751       597 

Average Sales Price:
  Oil (per Bbl). . . . . . . . . . . .   $19.87    $15.53    $15.25 
  Gas (per Mcf). . . . . . . . . . . .     2.13      1.45      1.63 

Costs Per BOE:
  Production costs, including 
    severance taxes (1). . . . . . . .   $ 6.68    $ 5.91    $ 3.94 
  Depreciation, depletion and 
    amortization . . . . . . . . . . .     3.81      3.40      3.09 

---------------------
(1)  Production costs per BOE in 1996 and 1995 were unusually high as a result
     of relatively high workover expenses with respect to properties acquired 
     in the 1995 Acquisition and the 1996 Acquisition which did not produce 
     related production improvements until subsequent periods.  Additionally,
     the Company's 1995 production costs were adversely affected by expenses 
     incurred in connection with plugging wells to comply with applicable 
     regulatory requirements.


EXPLORATION AND DEVELOPMENT ACTIVITIES

The Company drilled, or participated in the drilling of, the following number 
of wells during the periods indicated.  At December 31, 1996, the Company was 
in the process of drilling 7 gross (4.33 net) wells and was in the process of 
completing 8 gross (4.04 net) wells as producers which are not reflected in 
the following table.


                            1996           1995           1994
                       -------------   ------------   ------------
                       GROSS    NET    GROSS   NET    GROSS   NET
                       -----   -----   -----  -----   -----   ----
Exploratory:  
  Productive. . . . .    13     8.88     10    4.58     9     2.27 
  Dry . . . . . . . .     2     2.00      6    2.57    10     3.73 
                       -----   -----   -----  -----   -----   ----
    Total . . . . . .    15    10.88     16    7.15    19     6.00 
                       -----   -----   -----  -----   -----   ----
                       -----   -----   -----  -----   -----   ----

Development:  
  Productive. . . . .    16     9.93      1    0.44     -        -   
  Dry . . . . . . . .     5     3.20      -       -     -        -   
                       -----   -----   -----  -----   -----   ----
    Total . . . . . .    21    13.13      1    0.44     -        -   
                       -----   -----   -----  -----   -----   ----
                       -----   -----   -----  -----   -----   ----

Total:   
  Productive. . . . .    29    18.81     11    5.02     9     2.27 
  Dry . . . . . . . .     7     5.20      6    2.57    10     3.73 
                       -----   -----   -----  -----   -----   ----
    Total . . . . . .    36    24.01     17    7.59    19     6.00 
                       -----   -----   -----  -----   -----   ----
                       -----   -----   -----  -----   -----   ----



                                      15

<PAGE>

The Company does not own any drilling rigs and all of its drilling activities 
are conducted by independent contractors under standard drilling contracts.


PRODUCTIVE WELL SUMMARY

The following table sets forth the Company's gross and net interests in 
productive oil and gas wells as of December 31, 1996.  Productive wells are 
producing wells and wells capable of production.

                                                         ACTUAL (1)
                                                       -------------
                                                       GROSS     NET
                                                       -----     ---
Oil Wells . . . . . . . . . . . . . . . . . . . . .    2,323     708 
Gas Wells . . . . . . . . . . . . . . . . . . . . .    1,292     238 
                                                       -----     ---
  Total . . . . . . . . . . . . . . . . . . . . . .    3,615     946 
                                                       -----     ---
                                                       -----     ---

----------------
(1)  One well with multiple completions is counted as a single well.


ACREAGE

The following table sets forth certain information regarding the Company's 
developed and undeveloped leasehold acreage as of December 31, 1996.  Acreage 
in which the Company's interest is limited to royalty, overriding royalty, 
mineral and similar interests is excluded.


<TABLE>
                              DEVELOPED          UNDEVELOPED            TOTAL
                          -----------------   -----------------   -----------------
     REGION                GROSS      NET      GROSS      NET      GROSS      NET
     ------               -------   -------   -------   -------   -------   -------
<S>                       <C>       <C>       <C>       <C>       <C>       <C>
Permian Basin. . . . . .  220,859    48,038   124,781    72,373   345,640   120,411 
Gulf Coast . . . . . . .  138,569    57,595    41,123    34,962   179,692    92,557 
Rocky Mountain . . . . .   19,652     6,603    30,091    14,209    49,743    20,812 
Other. . . . . . . . . .   57,079    14,585    46,546    26,198   103,625    40,783 
                          -------   -------   -------   -------   -------   -------
Total. . . . . . . . . .  436,159   126,821   242,541   147,742   678,700   274,563 
                          -------   -------   -------   -------   -------   -------
                          -------   -------   -------   -------   -------   -------
</TABLE>

OTHER ACTIVITIES

MOLDOVA CONCESSION AGREEMENT.  In July 1995, the Republic of Moldova (located 
in Eastern Europe between Romania and the Ukraine) granted a Concession 
Agreement to Resource Development Company Limited, L.L.C. ("Redeco"), an 
entity not affiliated with the Company.  The Company has paid Redeco $90,000 
and agreed to bear the first $2.0 million of Concession expenses in return 
for a 50% interest in Redeco.  After the initial $2.0 million expenditure, 
which was incurred in August 1996, the Company and the other member of Redeco 
are responsible for bearing 50.0% each of future expenses.  To date, three 
wells, drilled by the government in the 1960s, have been reentered and two 
new wells have been completed by the Company in Moldova.  The Company 
continues to evaluate the Concession for further development.


TITLE TO PROPERTIES

The Company has obtained title opinions on substantially all of its producing 
properties and believes that it has satisfactory title to such properties in 
accordance with standards generally accepted in the oil and gas industry.  As 
is 



                                      16

<PAGE>

customary in the oil and gas industry, the Company performs a minimal title 
investigation before acquiring undeveloped properties.  A title opinion is 
obtained prior to the commencement of 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 
which the Company believes do not materially interfere with the use of or 
affect the value of such properties.


OPERATIONAL HAZARDS AND INSURANCE

The Company's operations are subject to the hazards and risks inherent in 
drilling and production and transportation of oil and gas, including fires, 
natural disasters, explosions, encountering formations with abnormal 
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which 
can result in loss of hydrocarbons, environmental pollution, personal injury 
or loss of life, severe damage to and destruction of properties of the 
Company and others, and suspension of operations.

The Company maintains insurance of various types to cover its operations, 
including liability coverage and operator's extra expense coverage which 
provides for care, custody and control of all material wells drilled by the 
Company as operator.  The Company believes that its insurance is adequate and 
customary for companies of a similar size engaged in operations similar to 
those of the Company, but losses could occur for uninsurable or uninsured 
risks or in amounts in excess of existing insurance coverage.  The Company's 
general policy is to only engage drilling contractors who provide substantial 
insurance coverage and name the Company as an additional named insured.  The 
occurrence of a significant adverse event, the risks of which are not fully 
covered by insurance, could have a material adverse effect on the Company's 
financial condition and results of operations. Moreover, no assurances can be 
given that the Company will be able to maintain adequate insurance in the 
future at rates it considers reasonable.















                                      17

<PAGE>

ITEM 3.  LEGAL PROCEEDINGS.

Special Note:  Certain statements set forth below under this caption 
constitute "forward-looking statements" within the meaning of the Reform Act. 
See "Special Note Regarding Forward-Looking Statements" for additional 
factors relating to such statements.

The Company is a defendant or codefendant in minor lawsuits that have arisen 
in the ordinary course of business.  While the outcome of these lawsuits 
cannot be predicted with certainty, management does not expect any of these 
to have a material adverse effect on the Company's consolidated financial 
condition or results of operations.


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

No matters were submitted to a vote of the Company's stockholders during the 
fourth quarter of the year ended December 31, 1996.















                                      18
<PAGE>

                                       PART II


ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

The Company completed its initial public offering of Common Stock on October
2, 1996.  On October 3, 1996 the Common Stock commenced trading on the Nasdaq
Stock Market's National Market (the "Nasdaq National Market") under the
trading symbol "COSE".  The following table sets forth the high and low
closing price for the period presented:

1996                                                           HIGH     LOW
                                                              ------   ------
     Fourth Quarter (October 3 inception of trading)........  $13.63   $11.75

The Company had approximately 1300 record and beneficial holders of its Common
Stock at December 31, 1996.

The Company has never declared or paid any cash dividends on its Common Stock.
The Company's Board of Directors does not anticipate paying any cash
dividends in the foreseeable future, as it intends to retain cash to finance
the growth of the Company's business.  In addition, the payment of any
dividends is prohibited by the terms of the Company's Credit Facility with its
secured lenders.  The payment of any cash dividends on the Common Stock in the
future will depend on such factors as the earnings, anticipated capital
requirements, and operating and financial condition of the Company and any
other factors deemed relevant by the Board of Directors.

                                     19
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA.

The following table sets forth selected financial data of Costilla Energy,
Inc. and Predecessor.  See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."  The historical information should be
read in conjunction with the Consolidated Financial Statements and the Notes
thereto included elsewhere herein.  Costilla Energy, Inc. and Predecessor
acquired significant producing oil and gas properties in certain of the
periods presented which affect the comparability of the historical financial
and operating information.  The historical results are not necessarily
indicative of the Company's future operations or financial results.

<TABLE>
                                                                    YEAR ENDED DECEMBER 31,
                                                     ---------------------------------------------------
                                                       1996       1995       1994       1993      1992
                                                     --------   --------   --------    -------   -------
<S>                                                  <C>        <C>        <C>         <C>       <C>
STATEMENT OF OPERATIONS DATA:
   Operating revenues.............................   $ 53,919   $ 21,693   $  7,637    $ 4,231   $ 2,362
   Total revenues.................................     55,026     21,816      7,836      4,397     2,887
   Expenses:
     Oil and gas production.......................     21,774     10,355      2,351      1,688     1,340
     General and administrative...................      5,238      3,571      1,184        952       388
     Compensation related to option settlement....          -        656          -          -         -
     Exploration and abandonments.................      2,550      1,650        793        218         4
     Depreciation, depletion and amortization.....     12,430      5,958      1,847        884       404
     Interest.....................................     11,281      4,591      1,458        605       365
     Other........................................          -          2          -          -         -
                                                     --------   --------   --------    -------   -------
   Income (loss) before income taxes and
     extraordinary item...........................      1,753     (4,967)       203         50        386
   Net income (loss)..............................     (4,440)    (4,970)       163         73        368

STATEMENT OF CASH FLOWS DATA:
   Net cash provided by (used in):
     Operating activities.........................   $ 12,350   $  6,366   $  1,527    $   322   $    140
     Investing activities.........................    (64,129)   (62,467)   (12,146)    (6,731)    (1,432)
     Financing activities.........................     61,531     58,830     10,618      6,315      1,450
OTHER FINANCIAL DATA:
   Capital expenditures...........................   $ 70,017   $ 62,220   $ 11,868    $ 6,862   $  3,720
   Adjusted EBITDA (1)............................     27,108      7,232      4,301      1,757      1,159
   Adjusted EBITDA/interest expense (1)...........       2.4x       1.6x       2.9x       2.9x      3.2x
BALANCE SHEET DATA (AS OF PERIOD END):
   Working capital................................   $ 10,320   $  2,496   $  1,081    $ 1,612   $   185
   Total assets...................................    162,790     87,367     24,904     13,290     6,675
   Total debt.....................................    100,262     71,494     23,613     12,034     5,352
   Redeemable predecessor capital.................          -     11,576          -          -         -
   Predecessor capital............................          -     (7,445)      (747)        51       434
   Stockholders' Equity...........................     40,569          -          -          -         -
</TABLE>
_____________

(1)  Adjusted EBITDA and the ratio of Adjusted EBITDA to interest expense are
     presented because of their wide acceptance as financial indicators of a
     company's ability to service or incur debt.  Adjusted EBITDA (as used
     herein) is calculated by adding interest, income taxes, depreciation,
     depletion and amortization, exploration and abandonment costs and
     extraordinary loss resulting from early extinguishment of debt, net of a
     deferred tax benefit, to net income (loss), and excluding a nonrecurring
     gain on the sale of substantially all of the assets of a subsidiary in
     1996.  The ratio of Adjusted EBITDA to interest expense is calculated by
     dividing Adjusted EBITDA by interest.  Adjusted EBITDA and the ratio of
     Adjusted EBITDA to interest expense should not be considered as
     alternatives to earnings (loss), or operating earnings (loss), as defined
     by generally accepted accounting principles, as indicators of the
     Company's financial performance or to cash flow as a measure of liquidity.

                                     20
<PAGE>

ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
          AND RESULTS OF OPERATIONS.

Special Note:  Certain statements set forth below under this caption
constitute "forward-looking statements" within the meaning of the Reform Act.
See "Special Note Regarding Forward-Looking Statements" for additional factors
relating to such statements.

GENERAL

Costilla is an independent energy company engaged in the exploration,
acquisition and development of oil and gas properties.  The Company's
predecessor began operating in 1988 and through mid-1995 had grown primarily
through a series of small acquisitions of oil and gas properties and the
exploitation of those properties.  In June 1995, Costilla consummated the 1995
Acquisition for a purchase price of approximately $46.6 million, and in June
1996, the 1996 Acquisition was consummated for a purchase price of
approximately $38.7 million.

To date, the Company has achieved its high rate of growth primarily through
acquisitions.  This has impacted its reported financial results in a number of
ways.  Properties sold by others frequently have not received focused
attention prior to sale.  After acquisition, certain of these properties are
in need of maintenance, workovers, recompletions and other remedial activity
not constituting capital expenditures, which substantially increase lease
operating expenses. The increased production and revenue resulting from these
expenditures is predominately realized in periods subsequent to the period of
expense.  In addition, the rapid growth of the Company has required it to
develop operating, accounting and administrative personnel compatible with its
increased size.  The Company believes it has now achieved a sufficient size to
expand its reserve base without a corresponding increase in its general and
administrative expense.  The Company also believes it now has a sufficient
inventory of prospects and the professional staff necessary to follow a more
balanced program of exploration and exploitation activities to complement its
acquisition efforts.

Costilla's strategy is to increase its oil and gas reserves, production and
cash flow from operations through a two-pronged approach which combines an
active exploration program with the acquisition and exploitation of proved
reserves.  In addition, Costilla continues to evaluate the acquisition of
undeveloped acreage for its exploration efforts.  Costilla has in-house
exploration expertise using 3-D seismic technology to identify new drilling
opportunities as well as for the exploitation of acquired properties.

Costilla has shown a significant increase in its oil and gas reserves and
production, especially due to the 1995 Acquisition and the 1996 Acquisition.
The following table sets forth certain operating data of Costilla for the
periods presented:

                                                    YEAR ENDED DECEMBER 31,
                                                    ------------------------
                                                    1996      1995      1994
                                                    ----      ----      ----
OIL AND GAS PRODUCTION:
   Oil (MBbls).................................     1,726       950       330
   Gas (Mmcf)..................................     9,205     4,806     1,600
   MBOE........................................     3,260     1,751       597
AVERAGE SALES PRICES (1):
   Oil (per Bbl)...............................    $19.87    $15.53    $15.25
   Gas (per Mcf)...............................      2.13      1.45      1.63
PRODUCTION COST (2):
   Per BOE (3).................................    $ 6.68    $ 5.91    $ 3.94
   Per dollar of sales.........................      0.40      0.48      0.31
DEPRECIATION, DEPLETION AND AMORTIZATION:
   Per BOE......................................   $ 3.81    $ 3.40    $ 3.09
   Per dollar of sales..........................     0.23      0.27      0.24

                                     21
<PAGE>

_____________

(1)  Before deduction of production taxes and net of any hedging results.

(2)  Production cost includes lease operating expenses and production and ad
     valorem taxes, if applicable, and excludes depreciation, depletion and
     amortization.

(3)  Production costs per BOE in 1995 and 1996 were unusually high as a result
     of relatively high workover expenses with respect to properties acquired
     in the 1995 Acquisition and the 1996 Acquisition which did not produce
     related production improvement until subsequent periods.  Additionally,
     the Company's 1995 production costs were adversely affected by expenses
     incurred in connection with plugging wells to comply with applicable
     regulatory requirements.

Costilla uses the successful efforts method of accounting for its oil and gas
activities.  Costs to acquire mineral interests in oil and gas properties, to
drill and equip exploratory wells that result in proved reserves, and to drill
and equip development wells are capitalized. Costs to drill exploratory wells
that do not result in proved reserves, geological, geophysical and seismic
costs, and costs of carrying and retaining unproved properties are expensed.
Capitalized costs of producing oil and gas properties, after considering
estimated dismantlement and abandonment costs and estimated salvage values,
are depreciated and depleted using the unit-of-production method.  Unproved
oil and gas properties that are individually significant are periodically
reviewed for impairment of value, and a loss is recognized at the time of
impairment by providing an impairment allowance.  Other unproved properties
are amortized based on the Company's experience of successful drilling and
average holding period.

The Company utilizes option contracts to hedge the effect of price changes on
a portion of its future oil and gas production.  Premiums paid and amounts
receivable under the option contracts are amortized and accrued to oil and gas
sales, respectively.  If market prices of oil and gas exceed the strike price
of put options, the options will expire unexercised, therefore, reducing the
effective price received for oil and gas sales by the cost of the related
option.  Conversely, if market prices of oil and gas decline below the strike
price of put options, the options will be exercised, therefore, increasing the
effective price received for oil and gas sales by the proceeds received from
the related option.  The net effect of the Company's commodity hedging
activities reduced oil and gas revenues by $1,705,000, $80,000 and $9,000 for
the years ended December 31, 1996, 1995, and 1994, respectively.

The Company utilizes interest rate swap agreements to reduce the potential
impact of increases in interest rates on floating-rate, long term debt.  If
market rates of interest experienced during the applicable swap term are below
the rate of interest effectively fixed by the swap agreement, the rate of
interest incurred by the Company will exceed the rate that would have been
experienced under the Credit Agreement.  The net effect of the Company's
interest rate hedging activities increased interest expense in 1996 by
$442,000 prior to repayment of the Company's floating rate debt and $8,000 for
the year ended December 31, 1995.  Concurrent with the payment of all of the
Company's floating rate debt from proceeds of the Offerings in the fourth
quarter of 1996, the interest rate swap agreements ceased to qualify as
hedges.  These interest rate swap agreements were marked-to-market and the
related liability recorded.  The liability for the two interest rate swap
agreements was $1,712,000 at December 31, 1996. The Company must mark the
agreements to market at the end of each reporting period and the net change
during the reporting period will be treated as investment gain or loss.  At
March 11, 1997 the value of the agreements was an approximate $1.5 million
liability.

The Company's predecessor was classified as a partnership for federal income
tax purposes.  Therefore, no income taxes were paid or provided for by the
Company prior to the Offerings.  Future tax amounts, if any, will be dependent
upon several factors, including but not limited to the Company's results of
operations.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995

The Company's total oil and gas revenues for the year ended December 31, 1996
were $53,919,000, representing an increase of $32,226,000 (149%) over revenues
of $21,693,000 in 1995.  This increase was primarily due to the 1996
Acquisition and 1995 Acquisition, which accounted for approximately
$12,754,000 and $14,059,000 of the revenue increase, respectively.  The
remainder of the increase was due to a combination of increased product
prices, successful drilling activities and the enhancement of existing
production.  The average oil price per barrel received in 1996 was $19.87
compared to $15.53 in 1995, a 28% increase, and the average gas price received
in 1996 was $2.13 compared to $1.45 in 1995, a 47% increase.

                                     22

<PAGE>

Oil and gas production was 3,260 MBOE in 1996 compared to 1,751 MBOE in 1995, 
an increase of 86%.  Of the 1,509 MBOE increase, approximately 723 MBOE was 
due to the properties acquired in the 1996 Acquisition and 562 MBOE was due 
to the properties acquired in the 1995 Acquisition.  The remainder of the 
increase was due to a combination of successful drilling activities and the 
enhancement of existing production.

Interest and other revenues were $40,000 for the year ended December 31, 1996 
compared to $123,000 in 1995, representing a decrease of $83,000, which was 
primarily comprised of $195,000 in losses on investments held for trading 
purposes and an increase in interest income of $67,000 in 1996 due to 
increased funds earning interest. Also in 1996, the Company realized gains of 
$ 1,067,000 on various transactions for which no comparable sales were 
recorded in 1995.

Oil and gas production costs in 1996 were $21,774,000 ($6.68 per BOE), 
compared to $10,355,000 in 1995 ($5.91 per BOE), representing an increase of 
$11,419,000 (110%), due principally to the 1996 Acquisition and to a lesser 
extent the 1995 Acquisition.  On a per BOE basis, production costs increased 
$0.77 due primarily to higher production costs per BOE for the properties 
acquired in the 1996 Acquisition.

General and administrative expenses for the year ended December 31, 1996 were 
$5,238,000, representing an increase of $1,667,000 (47%) from 1995 of 
$3,571,000.  The increase is primarily due to an increase in personnel and 
related costs necessary to accommodate the increased activities of the 
Company due to the 1995 and 1996 Acquisitions. However, as noted above, 
production volumes increased 86% and, therefore, general and administrative 
expenses per BOE decreased to $1.61 per BOE for the year ended December 31, 
1996 from the $2.04 per BOE in 1995.

Results of operations for the year ended December 31, 1995 include non-cash 
compensation expense of $656,000 deemed to have been accrued to a minority 
interest owner of the Company who was deemed to have benefited from the 
cancellation of an option to purchase an additional interest held by the 
other minority interest owner.

Exploration and abandonment expense increased to $2,550,000 in 1996 compared 
to $1,650,000 in 1995.  The Company incurred $913,000 of seismic costs for 
the year ended December 31, 1996, compared to $790,000 which were incurred in 
1995.  Dry hole and abandonment costs increased to $1,524,000 in 1996 from 
$860,000 in 1995.

Depreciation, depletion and amortization expense for 1996 was $12,430,000 
compared to $5,958,000 for 1995, representing an increase of $6,472,000 
(109%).  During 1996, depreciation, depletion and amortization on oil and gas 
production was provided at an average rate of $3.81 per BOE compared to $3.40 
per BOE for 1995.  The increases were due primarily to the 1996 and 1995 
Acquisitions.

Interest expense was $11,281,000 in 1996, compared to $4,591,000 in 1995.  
The $6,690,000 (146%) increase was attributable primarily to increased levels 
of debt which the Company used to finance the 1996 Acquisition.  The average 
amounts of applicable interest-bearing debt in 1996 and 1995 were $95,671,000 
and $49,972,000, respectively.  The effective annualized interest rate in 
1996 was 11.8%, as compared to 9.2% in 1995.

Results of operations for the year ended December 31, 1996 include an 
extraordinary charge of $4,975,000, net of the related deferred tax benefit 
of $1,042,000, related to the early extinguishment of the Company's prior 
bank credit facilities ( the "1995 Credit Facility and the Bridge Facility"). 
The 1995 Credit Facility was replaced by the Bridge Facility in June 1996 
and the Bridge Facility was paid off with proceeds from the Offerings in 
October 1996.

YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994

The Company's total oil and gas revenues for 1995 were $21,693,000, 
representing an increase of $14,056,000 (184%) over revenues of $7,637,000 in 
1994.  This increase was primarily due to the 1995 Acquisition which 
accounted for approximately $13,373,000 of the revenue increase.

Oil and gas production was 1,751 MBOE in 1995 and 597 MBOE in 1994. Of the 
1,154 MBOE increase, 1,099 MBOE was due to the properties acquired in the 
1995 Acquisition.

                                       23

<PAGE>

Interest and other revenues were $123,000 in 1995 compared to $87,000 in 
1994, representing an increase of $36,000 (41%), which was comprised of an 
increase in interest income of $59,000 in 1995 due to an increased amount of 
funds earning interest, partially offset by a decrease of other income of 
$23,000.  In 1994, the Company realized a gain of $112,000 on the sale of 
various properties for which there were no comparable gains in 1995.

Oil and gas production costs in 1995 were $10,355,000 ($5.91 per BOE), 
compared to $2,351,000 in 1994 ($3.94 per BOE), representing an increase of 
$8,004,000 (340%).  The major portion of the increase was due to increased 
production associated with the 1995 Acquisition.  In addition, certain 
acquired properties required remedial workovers and other activity 
immediately following acquisition resulting in unusual operating costs of 
approximately $600,000 during 1995.  In addition, $1,605,000 of operating 
costs were incurred in connection with properties acquired in late 1994.

General and administrative expense for 1995 was $3,571,000, representing an 
increase of $2,387,000 (202%) from 1994 expense of $1,184,000.  The increase 
is primarily due to an increase in personnel and related costs necessary to 
accommodate the increased activities of the Company due to the 1995 
Acquisition.

Results of operations for the year ended December 31, 1995 include non-cash 
compensation expense of $656,000 deemed to have been accrued to a minority 
interest owner of the Company in connection with the cancellation of an 
option to purchase an additional interest in the Company held by the other 
minority interest owner.

Exploration and abandonment expense increased to $1,650,000 in 1995 compared 
to $793,000 in 1994.  The increase of $857,000 (108%) was comprised 
principally of $790,000 of seismic costs.

Depreciation, depletion and amortization expense for 1995 was $5,958,000 
compared to $1,847,000 for 1994, representing an increase of $4,111,000 
(223%).  During 1995 depreciation, depletion and amortization on oil and gas 
production was provided at an average rate of $3.40 per BOE compared to $3.09 
per BOE for 1994.  The increase was due primarily to the 1995 Acquisition.

Interest expense was $4,591,000 in 1995 compared to $1,458,000 in 1994.  The 
$3,133,000 (215%) increase was attributable to increased levels of debt which 
the Company used to finance the 1995 Acquisition. The average amounts of 
applicable interest-bearing debt in 1995 and 1994 were $49,972,000 and 
$17,632,000, respectively.

LIQUIDITY AND CAPITAL RESOURCES

NET CASH USED IN OPERATING ACTIVITIES

For the year ended December 31, 1996, net cash provided by operating 
activities increased to $12.4 million from $6.4 million for 1995. Cash 
provided by operations, before changes in operating assets and liabilities, 
increased to $14.7 million from $1.7 million for 1995 due primarily to the 
1996 Acquisition and the increase in results of operations therefrom.

NET CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities for the year ended December 31, 1996 
was $64.1 million.  Approximately $38.7 million was used for the 1996 
Acquisition, $28.7 million was used for other oil and gas expenditures and 
$3.0 million was used for other property and equipment.  During the year 
ended December 31, 1996, approximately $6.3 million net cash was provided by 
sales of oil and gas properties. For the year ended December 31, 1995, net 
cash used in investing activities was $62.5 million.  Approximately $46.6 
million was used for the 1995 Acquisition, $14.9  million for additional 
acquisition of producing oil and gas properties and exploration and 
development activities and $1.0 million primarily for other property and 
equipment.

NET CASH PROVIDED BY FINANCING ACTIVITIES

The Company entered into a $125.0 million senior credit agreement in June 
1996, which was fully funded prior to the Company's initial public offering 
of Common Stock in October 1996.  Approximately $74.5 million was for the 

                                       24

<PAGE>

extension and refinancing of prior debt, $42.5 million was used for the 1996 
Acquisition and approximately $8.0 million was used for general corporate 
purposes.

CAPITAL RESOURCES

Funding for the Company's business activities has historically been provided 
by bank financings, cash flow from operations, private equity sales, property 
divestitures and joint ventures with industry participants.  The Company 
completed a $10 million private equity placement in February 1995.  
Subsequently, the 1995 Acquisition and the 1996 Acquisition were 
substantially funded by bank financings. The Company plans to finance its 
continuing operations and execute its business strategy with cash flow from 
operations and borrowings under the Credit Facility.  

While the Company regularly engages in discussions relating to potential 
acquisitions, the Company has no present agreement, commitment or 
understanding with respect to any such acquisition, other than the 
acquisition of undeveloped acreage and various mineral interests in its 
normal course of business.  Any future acquisition may require additional 
financing and will be dependent upon financing arrangements available at the 
time.

The Company believes that cash flow from operations will be sufficient for 
its budgeted 1997 capital expenditures.  However, because the Company's 
ultimate 1997 capital expenditures, future cash flows and the availability of 
financing are subject to a number of variables, there can be no assurance 
that the Company's capital resources will be sufficient to maintain its 
capital expenditures.  In addition, if the Company is unable to generate 
sufficient cash flow from operations to service its debt, it may be required 
to refinance all or a portion of its debt, including the Notes, or to obtain 
additional financing. There can be no assurance that any such refinancing 
would be possible or that any additional financing could be obtained.

The Company has the Credit Facility with NationsBank of Texas, N.A. (the 
"Bank").  The Credit Facility provides for a revolving line of credit with 
the availability of funds and letters of credit being subject to a borrowing 
base determination at least semi-annually.  The borrowing base provides for a 
maximum availability of $50.0 million (which amount was also the initial 
borrowing base), $100,000 of which was borrowed at December 31, 1996.  
Availability under the borrowing base is initially limited to $20.0 million 
for working capital and $30.0 million for acquisitions of oil and gas 
properties meeting certain criteria established by the Bank.  Borrowings 
under the Credit Facility bear interest at the Company's option at a floating 
rate which is at or above the NationsBank, N.A. prime rate or the LIBOR rate, 
depending on the percentage of committed funds which have been borrowed.  
Interest is payable quarterly and principal is amortized in twelve equal 
installments commencing, October 1998.  Under the Credit Facility, the 
Company is obligated to pay certain fees to the Bank, including a commitment 
fee based on the unused portion of the commitment.  The Credit Facility 
contains customary restrictive covenants (including restrictions on the 
payment of dividends and the incurrence of additional indebtedness) and 
requires the Company to maintain a current ratio of not less than 1.0 to 1.0, 
a ratio of Adjusted EBITDA to interest expense of not less than 2.0 to 1 and 
a minimum tangible net worth.  At December 31, 1996, the Company's current 
ratio was 2.0 to 1.0, the ratio of Adjusted EBITDA to interest expense was 
3.9 to 1 and the Company exceeded the tangible net worth test. 
Borrowings under the Credit Facility are secured by substantially 
all of the assets of the Company.

Although certain of the Company's costs and expenses may be affected by 
inflation, inflationary costs have not had a significant effect on the 
Company's results of operations.

CAPITAL EXPENDITURES

The Company requires capital primarily for the exploration, development and 
acquisition of oil and gas properties, the repayment of indebtedness and 
general working capital needs.  The Company's capital budget for 1997 is 
$26.0 million of which approximately $7.2 will be expended for exploratory 
drilling, approximately $13.6 million for exploitation activities, 
approximately $2.5 million for the purchase of undeveloped acreage and 
approximately $2.7 million for new seismic projects.


                                       25

<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

For the financial statements and supplementary data required by this Item 8, 
see the Index to Consolidated Financial Statements on page F-1 in this Form 
10-K.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
         FINANCIAL DISCLOSURE.

None.

                                       26

<PAGE>

                                    PART III.

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

The information required by this Item is incorporated herein by reference to 
the Company's definitive proxy statement which will be filed with the 
Commission within 120 days after December 31, 1996.

ITEM 11.  EXECUTIVE COMPENSATION.

The information required by this Item is incorporated herein by reference to 
the Company's definitive proxy statement which will be filed with the 
Commission within 120 days after December 31, 1996.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

The information required by this Item is incorporated herein by reference to 
the Company's definitive proxy statement which will be filed with the 
Commission within 120 days after December 31, 1996.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

The information required by this Item is incorporated herein by reference to 
the Company's definitive proxy statement which will be filed with the 
Commission within 120 days after December 31, 1996.

                                       27

<PAGE>
                                    PART IV


ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

FINANCIAL STATEMENTS

For a list of the consolidated financial statements filed as part of this
Form 10-K, see the Index to Consolidated Financial Statements on page F-1.

REPORTS ON FORM 8-K

No reports on Form 8-K were filed during the quarter ended December 31, 1996.

EXHIBITS

Exhibit
 Number         Description of Exhibit
-------         ----------------------
  *3.1      Certificate of Incorporation of the Company
  *3.2      Bylaws of the Company
  *4.1      Form of Notes or Global Certificate (included as Exhibit A to the
            Indenture)
  *4.2      Indenture dated as of October 1, 1996 by and between State Street
            Bank and Trust Company, as Trustee, and the Company, as Issuer
 **4.3      Form of Stock Certificate
***10.1     Credit Agreement dated October 10, 1996 between NationsBank of
            Texas, N.A., as agent, the Lenders named therein and the Company
  *10.2     Lease Agreement dated January 12, 1996 between Independence
            Plaza, Ltd. and Costilla Energy, L.L.C.
  *10.3     Concession Agreement dated July 6, 1995 between the Government of
            the Republic of Moldova and Resource Development Company Ltd.,
            L.L.C. (DE)
  *10.4     Consolidation Agreement dated October 8, 1996
  *10.5     1996 Stock Option Plan
  *10.6     Outside Directors Stock Option Plan
  *10.7     Employment Agreement between the Company and Bobby W. Page
            effective June 30, 1996
  *10.8     Employment Agreement between the Company and Cadell S. Liedtke
            effective October 8, 1996
  *10.9     Employment Agreement between the Company and Michael J. Grella
            effective October 8, 1996
  *10.10    Employment Agreement between the Company and Henry G. Musselman
            effective October 8, 1996
  *10.11    Purchase and Sale Agreement dated April 3, 1995 by and between
            Parker & Parsley Development L.P., Parker & Parsley Producing
            L.P. and Parker & Parsley Gas Processing Co., as Seller, and
            Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
            Purchaser
  *10.12    Purchase and Sale Agreement dated March 8, 1996 by and between
            Parker & Parsley Development L.P., Parker & Parsley Producing
            L.P. and Parker & Parsley Gas Processing Co., as Seller, and
            Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
            Purchaser
  *10.13    Bonus Incentive Plan

                                       28

<PAGE>

***10.14    Letter Agreement dated December 18, 1996 by and between Statewide
            Minerals, Inc., as Seller, Boldrick Partners, as Buyer
***10.15    Stock Purchase Agreement dated December 31, 1996 by and between ERI
            Investments, Inc. and the Company
***12.1     Computation of Ratio of Adjusted EBITDA to Interest Expense
 **16.1     Letter Regarding Change of Accountants
***21.1     Subsidiaries of the Registrant
***23.1     Consent of KPMG Peat Marwick LLP
***23.2     Consent of Williamson Petroleum Consultants, Inc.
***23.3     Consent of Elms, Faris & Co., P.C.
***24.1     Power of Attorney
***24.2     Certified copy of resolution of Board of Directors of Costilla
            Energy, Inc. authorizing signature by Power of Attorney
***27.1     Financial Data Schedule

*    Incorporated by reference to Registration Statement on Form S-1, File
     No. 333-08909
**   Incorporated by reference to Registration Statement on Form S-1, File
     No. 333-08913.
***  Filed herewith

FINANCIAL STATEMENT SCHEDULES

     No Financial Statement Schedules are required with this report.  For a list
     of the consolidated financial statements filed as a part of this report,
     see the Index to Consolidated Financial Statements on page F-1.

REPORTS ON FORM 8-K

     The Company did not file a report on Form 8-K during the last quarter of
     the period covered by this report.

                                       29

<PAGE>

                             S I G N A T U R E S

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 be signed
on its behalf by the undersigned, thereunto duly authorized.

                            COSTILLA ENERGY, INC.

Date:  March 26, 1997       By: */s/ CADELL S. LIEDTKE
                                --------------------------------
                                Cadell S. Liedtke
                                Chairman of the Board
                                and Chief Executive Officer

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

Date:  March 26, 1997      */s/ CADELL S. LIEDTKE
                                --------------------------------
                                Cadell S. Liedtke
                                Chairman of the Board
                                and Chief Executive Officer

Date:  March 26, 1997      */s/ MICHAEL J. GRELLA
                                --------------------------------
                                Michael J. Grella
                                President and Chief Operating Officer
                                and Director

Date:  March 26, 1997      */s/ HENRY G. MUSSELMAN
                                --------------------------------
                                Henry G. Musselman
                                Executive Vice President
                                and Director

Date:  March 26, 1997      */s/ W. D. KENNEDY
                                --------------------------------
                                W. D. Kennedy
                                Director


Date:  March 26, 1997      */s/ JERRY J. LANGDON
                                --------------------------------
                                Jerry J. Langdon
                                Director

Date:  March 26, 1997       /s/ BOBBY W. PAGE
                                --------------------------------
                                Bobby W. Page
                                Senior Vice President and Chief Financial
                                Officer (principal accounting officer)

Date:  March 26, 1997  *By: /s/ BOBBY W. PAGE
                                --------------------------------
                                Bobby W. Page
                                Agent and Attorney in fact

                                       30

<PAGE>



                    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<S>                                                                                <C>
Financial Statements of Costilla Energy, Inc.:
  Independent Auditors' Reports . . . . . . . . . . . . . . . . . . . . . . . .   F - 2
  Consolidated Balance Sheets as of December 31, 1996 and 1995. . . . . . . . .   F - 4
  Consolidated Statements of Operations for the years ended December31, 1996,
       1995 and 1994. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   F - 5
  Consolidated Statements of Stockholders' Equity for the years
  ended December 31, 1996, 1995 and 1994. . . . . . . . . . . . . . . . . . . .   F - 6
  Consolidated Statements of Cash Flows for the years ended December 31, 1996,
        1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   F - 7
  Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . .   F - 8
</TABLE>




























                                      F-1

<PAGE>

                          INDEPENDENT AUDITORS' REPORT



The Board of Directors and Stockholders
Costilla Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Costilla 
Energy, Inc. and subsidiaries as of December 31, 1996 and 1995, and the 
related consolidated statements of operations, stockholders' equity, and cash 
flows for the years then ended.  These consolidated financial statements are 
the responsibility of the Company's management.  Our responsibility is to 
express an opinion on these consolidated 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 consolidated financial statements referred to above 
present fairly, in all material respects, the financial position of Costilla 
Energy, Inc. and subsidiaries as of December 31, 1996 and 1995, and the 
results of their operations and their cash flows for the years then ended, in 
conformity with generally accepted accounting principles.


                                       /s/ KPMG PEAT MARWICK LLP
                                       ---------------------------------
                                       KPMG PEAT MARWICK LLP

Midland, Texas
March 10, 1997







                                      F-2

<PAGE>


                         INDEPENDENT AUDITORS' REPORT



The Board of Directors and Stockholders
Costilla Energy, Inc.:

We have audited the accompanying consolidated statement of operations, 
stockholders' equity, and cash flows of the predecessor entities of Costilla 
Energy, Inc. and subsidiaries, as detailed in Note 1 to the consolidated 
financial statements, for the year ended December 31, 1994.  These 
consolidated financial statements are the responsibility of the Company's 
management.  Our responsibility is to express an opinion on these financial 
statements based on our audit.

We conducted our audit 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 audit provides a 
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above 
present fairly, in all material respects, the results of operations and the 
cash flows of Costilla Energy, Inc. and subsidiaries for the year ended 
December 31, 1994, in conformity with generally accepted accounting 
principles.


                                       /s/ ELMS, FARIS & CO., P. C.
                                       ------------------------------------
                                       ELMS, FARIS & CO., P. C.


Midland, Texas
March 31, 1995

















                                      F-3

<PAGE>

                             COSTILLA ENERGY, INC.

                          CONSOLIDATED BALANCE SHEETS
                                 (IN THOUSANDS)

<TABLE>
                ASSETS
                                                                      DECEMBER 31,
                                                                 ---------------------
                                                                     1996       1995
                                                                 ---------    --------
<S>                                                              <C>           <C>
CURRENT ASSETS:
  Cash and cash equivalents                                      $  12,618    $  2,866 
  Accounts receivable:
    Trade, net                                                       6,675       3,154 
    Affiliates                                                         332         507 
    Oil and gas sales                                                9,031       3,915 
  Prepaid and other current assets                                   1,753         439 
                                                                 ---------    --------
          Total current assets                                      30,409      10,881
                                                                 ---------    --------

PROPERTY, PLANT AND EQUIPMENT, AT COST:
  Oil and gas properties, using the successful efforts
   method of accounting:
    Proved properties                                              140,477      79,897 
    Unproved properties                                              4,482       2,903 
  Accumulated depletion, depreciation and amortization             (20,435)     (9,413)
                                                                 ---------    --------
                                                                   124,524      73,387 
  Other property and equipment, net                                  2,420         679
                                                                 ---------    --------
          Total property, plant and equipment                      126,944      74,066
                                                                 ---------    --------

OTHER ASSETS:
  Deferred charges (Note 2)                                          4,503       1,736 
  Note receivable - other                                              250         - 
  Note receivable - affiliate                                          684         684 
                                                                 ---------    --------
          Total other assets                                         5,437       2,420
                                                                 ---------    --------
                                                                 $ 162,790    $ 87,367
                                                                 ---------    --------
                                                                 ---------    --------

              LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES:
  Current maturities of long-term debt                           $      98    $    -  
  Trade accounts payable                                            12,718       5,467 
  Undistributed revenue                                              3,517       1,227 
  Other current liabilities                                          3,756       1,533 
                                                                 ---------    --------
          Total current liabilities                                 20,089       8,227 
                                                                 ---------    --------

LONG-TERM DEBT, LESS CURRENT MATURITIES  (NOTE 7)                  100,262      71,494 
                                                                 ---------    --------
DEFERRED REVENUE                                                       -         3,319 
                                                                 ---------    --------
OTHER NONCURRENT LIABILITIES                                         1,870         196 
                                                                 ---------    --------
REDEEMABLE PREDECESSOR CAPITAL                                         -        11,576 
                                                                 ---------    --------
STOCKHOLDERS' EQUITY (DEFICIT):
  Predecessor capital                                                  -        (7,445)
  Preferred stock, $.10 par value (3,000,000 shares authorized;
   no shares outstanding                                               -           -
  Common stock, $.10 par value (20,000,000 shares authorized;
   10,475,000 shares outstanding at December 31, 1996)               1,047         - 
  Additional paid-in capital                                        41,081         -  
  Retained earnings (deficit)                                       (1,559)
                                                                 ---------    --------
          Total stockholders' equity (deficit)                      40,569      (7,445)
                                                                 ---------    --------
COMMITMENTS AND CONTINGENCIES (NOTE 9)                                 -           -
                                                                 ---------    --------

                                                                 $ 162,790    $ 87,367 
                                                                 ---------    --------
                                                                 ---------    --------
</TABLE>

See accompanying notes to consolidated financial statements.


                                     F-4

<PAGE>

                             COSTILLA ENERGY, INC.

                   CONSOLIDATED STATEMENTS OF OPERATIONS

                    (IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
                                                           YEARS ENDED DECEMBER 31,
                                                      ---------------------------------
                                                         1996         1995       1994
                                                      --------     --------    --------
<S>                                                   <C>           <C>         <C>
REVENUES:
  Oil and gas sales                                   $ 53,919     $ 21,693    $  7,637 
  Interest and other                                        40          123          87 
  Gain on sale of assets                                 1,067          -           112 
                                                      --------     --------    --------
                                                        55,026       21,816       7,836 
                                                      --------     --------    --------

EXPENSES:
  Oil and gas production                                21,325       10,024       2,349 
  Oil and gas production - affiliates                      449          331           2 
  General and administrative                             4,682        2,910         634 
  General and administrative - affiliates                  556          661         550 
  Compensation related to option settlement                -            656         -
  Exploration and abandonments                           2,550        1,652         793
  Depreciation, depletion and amortization              12,430        5,958       1,847 
  Interest                                              11,281        4,591       1,458 
                                                      --------     --------    --------
                                                        53,273       26,783       7,633 
                                                      --------     --------    --------

    Income (loss) before federal income taxes and
     extraordinary item                                  1,753       (4,967)        203 

PROVISION FOR FEDERAL INCOME TAXES
  Current                                                  176            3           8 
  Deferred                                               1,042          -            32 
                                                      --------     --------    --------
    Income (loss) before extraordinary item                535       (4,970)        163 
    Extraordinary loss resulting from early
    extinguishment of debt, net of the related 
    deferred tax benefit of $1,042 (Notes 5 and 7)      (4,975)         -           -
                                                      --------     --------    --------

NET INCOME (LOSS)                                     $ (4,440)    $ (4,970)   $    163 
                                                      --------     --------    --------
                                                      --------     --------    --------

NET INCOME (LOSS) APPLICABLE TO PREDECESSOR CAPITAL   $ (5,337)    $ (7,812)   $    163 
                                                      --------     --------    --------
                                                      --------     --------    --------

INCOME (LOSS) PER SHARE:
  Income (loss) before extraordinary item             $   0.08     $  (0.96)   $   0.03 
  Extraordinary loss resulting from
   early extinguishment of debt, net of
   deferred tax benefit                                  (0.77)         -           -
                                                      --------     --------    --------
  Net income (loss)                                   $  (0.69)    $  (0.96)   $   0.03 
                                                      --------     --------    --------
                                                      --------     --------    --------

Net income (loss) applicable to predecessor capital   $  (0.82)    $  (1.50)   $   0.03 
                                                      --------     --------    --------
                                                      --------     --------    --------

WEIGHTED AVERAGE SHARES OUTSTANDING                      6,473        5,200       5,200 
                                                      --------     --------    --------
                                                      --------     --------    --------
</TABLE>

See accompanying notes to consolidated financial statements.

                                     F-5
<PAGE>
                                       
                             COSTILLA ENERGY, INC.


          CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
                                (IN THOUSANDS)


<TABLE>
                                                                                                   TOTAL
                                                                                               STOCKHOLDERS'
                                                                      ADDITIONAL   RETAINED     EQUITY AND
                                               PREDECESSOR   COMMON    PAID-IN     EARNINGS    PREDECESSOR
                                                 CAPITAL     STOCK     CAPITAL     (DEFICIT)     CAPITAL
                                               -----------   ------   ----------   --------    -------------
<S>                                              <C>         <C>      <C>          <C>            <C>
BALANCE AT DECEMBER 31, 1993 (PREDECESSOR)       $    51     $    -   $      -     $     -        $    51 
  Net income                                         163          -          -           -            163 
  Withdrawals                                       (961)         -          -           -           (961)
                                                 -------     ------   --------     -------        -------

BALANCE AT DECEMBER 31, 1994 (PREDECESSOR)          (747)         -          -           -           (747)

  Issuance of predecessor interest                 1,266          -          -           -          1,266 
  Issuance costs                                    (753)         -          -           -           (753)
  Net loss                                        (4,970)         -          -           -         (4,970)
  Withdrawals                                        (55)         -          -           -            (55)
  Imputed capital contribution on 
    settlement of option                             656          -          -           -            656 
  Preferred return and accretion of  
    redeemable predecessor capital                (2,842)         -          -           -         (2,842)
                                                 -------     ------   --------     -------        -------

BALANCE AT DECEMBER 31, 1995 (PREDECESSOR)        (7,445)         -          -           -         (7,445)

  Net loss                                        (2,881)         -          -      (1,559)        (4,440)
  Preferred return and accretion of  
    redeemable predecessor capital                (2,456)         -          -           -         (2,456)
  Common stock issued, net                             -        527     60,052           -         60,579 
  Distributions to members                        (4,218)                4,218           -              -
  Transfer of predecessor capital and  
    issuance of common stock pursuant
    to the Offerings                              17,000        520    (23,189)          -         (5,669)
                                                 -------     ------   --------     -------        -------

BALANCE AT DECEMBER 31, 1996                     $     -     $1,047   $ 41,081     $(1,559)       $40,569 
                                                 -------     ------   --------     -------        -------
                                                 -------     ------   --------     -------        -------
</TABLE>



         See accompanying notes to consolidated financial statements. 



                                      F-6
<PAGE>
                                       
                              COSTILLA ENERGY, INC.


                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (IN THOUSANDS)


<TABLE>
                                                           YEARS ENDED DECEMBER 31,
                                                      ---------------------------------
                                                        1996         1995        1994
                                                      ---------    --------    --------
<S>                                                   <C>          <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES: 

  NET INCOME (LOSS)                                   $  (4,440)   $ (4,970)   $    163

  ADJUSTMENTS TO RECONCILE NET INCOME 
    (LOSS) TO NET CASH PROVIDED BY 
    OPERATING ACTIVITIES:  
    Depreciation, depletion and amortization             12,430       5,958       1,847
    Exploration and abandonments                            491           -           -
    Amortization of deferred charges                      1,131         137           -
    Other noncash                                           103         (75)         35
    Compensation related to option settlement                 -         656           -
    Gain on sale of oil and gas properties               (1,067)          -        (112)
    Extraordinary loss resulting from early 
      extinguishment of debt                              6,017           -           -
                                                      ---------    --------    --------
                                                         14,665       1,706       1,933

    Changes in operating assets and liabilities: 
      Increase in accounts receivable                    (8,462)     (4,818)     (1,535)
      Decrease (increase) in other assets                (1,076)       (216)        301
      Increase in accounts payable                        6,067       3,745         723
      Increase in other liabilities                       4,475       2,655         102
      Increase (decrease) in deferred revenue            (3,319)      3,294           3
                                                      ---------    --------    --------
        Net cash provided by operating activities        12,350       6,366       1,527
                                                      ---------    --------    --------

CASH FLOWS FROM INVESTING ACTIVITIES:  

    Additions to oil and gas properties                 (67,010)    (61,500)    (11,819)
    Proceeds from sale of oil and gas properties          6,388           -         112
    Additions to other property and equipment            (3,007)       (720)        (49)
    Advances on notes receivable - other                   (500)          -           -
    Advances on affiliate notes receivable                    -        (247)       (390)
                                                      ---------    --------    --------
        Net cash used in investing activities           (64,129)    (62,467)    (12,146)
                                                      ---------    --------    --------

CASH FLOWS FROM FINANCING ACTIVITIES:  

    Borrowings under long-term debt                     228,707      62,704      11,579
    Payments of long-term debt                         (199,840)    (11,232)          -
    Proceeds from issuance of common stock, net          60,579           -           -
    Proceeds from redeemable predecessor capital              -      10,000           -
    Deferred loan and financing costs                    (8,191)     (2,587)          -
    Redemption of member's interest                     (15,506)          -           -
    Distributions to members and withdrawals             (4,218)        (55)       (961)
                                                      ---------    --------    --------
        Net cash provided by financing activities        61,531      58,830      10,618
                                                      ---------    --------    --------

NET INCREASE (DECREASE) IN CASH AND 
  CASH EQUIVALENTS                                        9,752       2,729          (1)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD            2,866         137         138
                                                      ---------    --------    --------
CASH AND CASH EQUIVALENTS, END OF PERIOD              $  12,618    $  2,866    $    137
                                                      ---------    --------    --------
                                                      ---------    --------    --------
</TABLE>


See accompanying notes to consolidated financial statements.    



                                      F-7
<PAGE>


                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  ORGANIZATION AND NATURE OF OPERATIONS

     Costilla was incorporated in Delaware in June 1996 to consolidate and 
continue the activities previously conducted by Costilla Energy, L.L.C., a 
Texas limited liability company (the "LLC"), and its wholly owned 
subsidiaries, to acquire the assets of CSL Management Corporation ("CSL") 
(which owns certain office equipment used by the Company), and to acquire the 
stock of Valley Gathering Company ("Valley").  Costilla was formed for the 
purpose of conducting a $60 million initial public offering of common stock 
and a $100 million senior notes offering (the "Offerings"), which Offerings 
were completed in early October 1996.

     At December 31, 1994, the financial statements of the LLC and its 
affiliates were combined.  The combining companies were owned by three 
individuals prior to the formation of the LLC.  Such individuals owned 
exactly the same proportionate interest in each of the combining companies 
prior to their combination into the LLC on February 14, 1995.  Each 
individual held exactly the same proportionate interest in the combining 
companies as was their proportionate interest in the LLC after its formation. 
Management believes, based on the exact same proportionate interests being 
held in the combining companies and the LLC before and after the date of its 
formation, that the combination lacks substance and is not the purchase of a 
minority interest.

     The LLC was formed on February 14, 1995 as the successor to CSL 
Partners, a Texas general partnership, which was organized on January 11, 
1989.  Subsequent to the formation of the LLC, NationsBank Capital 
Corporation ("NBCC") acquired a 30% interest in the LLC as described in Note 
12.  Contemporaneously with the closings of the Offerings: (1) the redeemable 
membership interests of NBCC in the LLC were redeemed for $15.5 million; (2) 
the LLC was merged into Costilla (the "Merger") and an aggregate of 5,200,000 
shares of Common Stock were issued to the members of the LLC; (3) Costilla 
acquired all of the issued and outstanding stock of Valley and the assets of 
CSL for $0.7 million; and (4) $4.2 million in distributions were made to the 
members of the LLC, $3.4 million of which was provided to former members for 
certain income tax effects of the Merger.  The LLC was an unincorporated 
association of several individuals and a corporation and ceased to exist on 
the date of the Offerings.

     The Company is an oil and gas exploration and production concern with 
properties located principally in West Texas, South Texas, and the Rocky 
Mountain regions of the United States.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     PRINCIPLES OF CONSOLIDATION

     As of December 31, 1996, the consolidated financial statements include 
the accounts of the Company and its wholly-owned subsidiaries.  The Company 
proportionately consolidates less than 100%-owned oil and gas partnerships 
and joint ventures in accordance with industry practice.  All significant 
accounts and transactions between the Company and its subsidiaries have been 
eliminated. 

     At December 31, 1996 Costilla had three wholly owned subsidiaries:  (i) 
Costilla Petroleum Corporation, a Texas corporation ("CPC"), which operated 
properties owned by Costilla and owned minor interests in the same 
properties, (ii)  Statewide Minerals, Inc., a Texas corporation 
("Statewide"), which had engaged in the purchase of small royalty and mineral 
interests; and (iii) Valley, which owns several small gas gathering systems, 
a small gas processing plant, certain salt water disposal systems and gas 
compressors.  Costilla and CPC were the sole members of two Texas limited 
liability companies through which the Company's Moldovan operations are 
conducted.


                                      F-8

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


USE OF ESTIMATES

     Preparation of the accompanying consolidated 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.

     CASH AND CASH EQUIVALENTS

     For purposes of the statements of cash flows, cash and cash equivalents 
include cash on hand and depository accounts held by banks.

     CONCENTRATIONS OF CREDIT RISK

     Financial instruments that potentially expose the Company to 
concentrations of credit risk consist primarily of unsecured accounts 
receivable from unaffiliated working interest owners and crude oil and 
natural gas purchasers. During the year ended December 31, 1996, the Company 
had sales to one customer which accounted for 11.2% of total revenues.  
During the year ended December 31, 1995, the Company had sales to one 
customer which accounted for 17.7% of total revenues.

     TRADE RECEIVABLES

     Trade receivables generally consist of amounts due from outside working 
interest owners for their proportionate share of drilling and operating costs 
incurred by the Company, as operator of the related properties.

     HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

     The financial instruments that the Company accounts for as hedging 
contracts must meet the following criteria:  the underlying asset or 
liability must expose the Company to price or interest rate risk that is not 
offset in another asset or liability, the hedging contract must reduce that 
price or interest rate risk, and the instrument must be designated as a hedge 
at the inception of the contract and throughout the contract period.  In 
order to qualify as a hedge, there must be clear correlation between changes 
in the fair value of the financial instrument and the fair value of the 
underlying asset or liability such that changes in the market value of the 
financial instrument will be offset by the effect of price or interest rate 
changes on the exposed items.

     Premiums paid for commodity option contracts and interest rate swap 
agreements which qualify as hedges are amortized to oil and gas sales and 
interest expense, respectively, over the terms of the agreements.  
Unamortized premiums are included in other assets in the consolidated balance 
sheet.  Amounts receivable under the commodity option contracts and interest 
rate swap agreements are accrued as an increase in oil and gas sales and a 
reduction of interest expense, respectively, for the applicable periods.  
When these derivative financial instruments cease to qualify as hedges, these 
instruments are classified as investments held for trading purposes.  
Investments held for trading purposes are marked to market at the end of each 
reporting period and the net balance change is recorded as other income in 
the consolidated statement of operations for the applicable period.

     OIL AND GAS PROPERTIES

     The Company uses the successful efforts method of accounting for oil and 
gas producing activities.  Costs to acquire mineral interests in oil and gas 
properties, to drill and equip exploratory wells that find proved reserves, 
and to drill and equip development wells are capitalized.  Costs to drill 
exploratory wells that do not find proved reserves, geological and 
geophysical costs, and costs of carrying and retaining unproved properties 
are expensed.


                                      F-9

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Unproved oil and gas properties that are individually significant are 
periodically assessed for impairment of value, and a loss is recognized at 
the time of impairment by providing an impairment allowance.  Other unproved 
properties are amortized based on the Company's experience of successful 
drilling and average holding period.  Capitalized costs of producing oil and 
gas properties, after considering estimated dismantlement and abandonment 
costs and estimated salvage values, are depreciated and depleted by the 
unit-of-production method.  Support equipment and other property and 
equipment are depreciated over their estimated useful lives of the assets, 
which range from 5 to 7 years.

     Prior to the adoption of FAS 121 on January 1, 1995, the Company's 
aggregate oil and gas properties were carried at cost, not in excess of total 
estimated undiscounted future net revenues, on a worldwide basis.

     On sale or retirement of a complete unit of a proved property, the cost 
and related accumulated depreciation, depletion, and amortization are 
eliminated from the property accounts, and the resultant gain or loss is 
recognized.  On retirement or sale of a partial unit of proved property, the 
cost is charged to accumulated depreciation, depletion, and amortization with 
a resulting gain or loss recognized in income.

     On sale of an entire interest in an unproved property for cash or cash 
equivalent, gain or loss on the sale is recognized, taking into consideration 
the amount of any recorded impairment if the property had been assessed 
individually.  If a partial interest in an unproved property is sold, the 
amount received is treated as a reduction of the cost of the interest 
retained.

     IMPAIRMENT OF LONG-LIVED ASSETS

     As of January 1, 1995, the Company adopted the provisions of Statement 
of Financial Accounting Standards No. 121 - ACCOUNTING FOR THE IMPAIRMENT OF 
LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF ("FAS 121").  
Consequently, the Company reviews its long-lived assets to be held and used, 
including oil and gas properties accounted for under the successful efforts 
method of accounting, whenever events or circumstances indicate that the 
carrying value of those assets may not be recoverable.  An impairment loss is 
indicated if the sum of the expected future cash flows, on a depletable unit 
basis, is less than the carrying amount of such assets.  In this 
circumstance, the Company recognizes an impairment loss for the amount by 
which the carrying amount of the asset exceeds the fair value of the asset.

     DEFERRED CHARGES

     The Company capitalized certain costs incurred in connection with the 
issuance of $100 million of senior notes and with obtaining the 1996 Credit 
Facility (see Note 7 for definitions and descriptions of each).  These costs 
are being amortized over the lives of the related instruments.

     DEFERRED REVENUE

     In November 1995, the Company entered into gas sales agreements whereby 
it committed to delivery of a total of 2,379,000 MMbtu, from December 1, 1995 
through December 31, 1996, for a total fixed price of $3,429,610.  Income 
from such agreements is generally recognized in the period of delivery.

     REVENUE RECOGNITION

     The Company uses the sales method of accounting for crude oil revenues.  
Under this method, revenues are recognized based on actual volumes of oil 
sold to purchasers.

     The Company uses the entitlements method of accounting for natural gas 
revenues.  Under this method, revenues are recognized based on actual 
production of natural gas.  Natural gas revenues would not have been 
significantly altered in any period had the sales method of recognizing 
natural gas revenues been utilized.


                                      F-10

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     STOCK-BASED COMPENSATION

     The Company accounts for employee stock-based compensation using the 
intrinsic value method prescribed by Accounting Principles Board Opinion No. 
25, "Accounting for Stock Issued to Employees" ("APB 25").  Accordingly, the 
Company has only adopted the disclosure provisions of Statement of Financial 
Accounting Standards No. 123, "Accounting for Stock-Based Compensation" 
("SFAS 123").  See Note 12 for the pro forma disclosures of compensation 
expense determined under the fair-value provisions of SFAS 123.

     INCOME TAXES

     The Company accounts for income taxes in accordance with the provisions 
of Statement of Financial Accounting Standards No. 109, "Accounting for 
Income Taxes" ("SFAS 109").  Under the asset and liability method of SFAS 
109, deferred tax assets and liabilities are recognized for the future tax 
consequences attributable to differences between the financial statement 
carrying amounts of existing assets and liabilities and their respective tax 
bases.  Deferred tax assets and liabilities are measured using enacted tax 
rates expected to apply to taxable income in the years in which those 
temporary differences are expected to be recovered or settled.  Under SFAS 
109, the effect on deferred tax assets and liabilities of a change in tax 
rate is recognized in income in the period that includes the enactment date.

     EARNING PER SHARE

     Primary net income (loss) per share is computed based on the weighted 
average number of shares of common stock and common stock equivalents 
outstanding during the period.  Common stock equivalent shares arising from 
stock options are computed using the treasury stock method.  There were no 
potentially dilutive securities, other than common stock equivalents.  
Consequently, primary and fully diluted earnings per share do not differ.  
For the periods prior to the Offerings, the weighted average shares 
outstanding attributable to predecessor capital are the 5,200,000 shares 
issued to the predecessor members upon conversion of the LLC.

     ENVIRONMENTAL

     The Company is subject to extensive Federal, state and local 
environmental laws and regulations.  These laws, which are constantly 
changing, regulate the discharge of materials into the environment and may 
require the Company to remove or mitigate the environmental effects of the 
disposal or release of petroleum or chemical substances at various sites.  
Environmental expenditures are expensed or capitalized depending on their 
future economic benefit.  Expenditures that relate to an existing condition 
caused by past operations and that have no future economic benefits are 
expensed.  Liabilities for expenditures of a noncapital nature are recorded 
when environmental assessment and/or remediation is probable, and the costs 
can be reasonably estimated.

     RECLASSIFICATIONS

     Certain reclassifications have been made to the 1995 and 1994 financial 
statements to conform to the 1996 presentation.

(3)  ACQUISITION OF OIL AND GAS PROPERTIES

     On June 14, 1996, the Company consummated the purchase from Parker and 
Parsley Petroleum Company of certain oil and gas properties for an estimated 
adjusted purchase price of approximately $38.7 million (the "1996 
Acquisition").  The properties are located primarily in south and west Texas. 
The transaction was accounted for using the purchase method.  The results of 
operations of the acquired properties are included in the Consolidated 
Statements of Operations as of the acquisition closing date, June 14, 1996.  
The Company sold for approximately $3.3 million its wholly-owned subsidiary, 
Costilla Pipeline Corporation, which owned the Three Rivers Pipeline 


                                      F-11

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


purchased in the 1996 Acquisition.  Certain other acquired properties, which 
were located outside the Company's areas of strategic focus, were sold in 
1996.  No gain or loss was recorded on these sales.

     In June 1995 the Company acquired a group of oil and gas properties from 
Parker and Parsley Petroleum Company for approximately $46.6 million (the 
"1995 Acquisition").  The properties are located in the Permian Basin, Gulf 
Coast and Rocky Mountain regions.  The transaction was accounted for using 
the purchase method.  The results of operations of the acquired properties 
are included in the Consolidated Statements of Operations as of the 
acquisition date of June 12, 1995. Certain other acquired properties, which 
were located outside the Company's areas of strategic focus, were sold in 
1995.  No gain or loss was recorded on these sales.

     PRO FORMA RESULTS OF OPERATIONS (UNAUDITED)

     The following table reflects the pro forma results of operations as 
though the 1995 Acquisition and 1996 Acquisition, net of the related 
properties sold, had occurred on January 1, 1995.  The pro forma amounts are 
not necessarily indicative of the results that may be reported in the future. 

                                                                YEARS ENDED
                                                                DECEMBER 31,
                                                              1996      1995
                                                            -------   --------
                                                              (IN THOUSANDS)
      Revenues. . . . . . . . . . . . . . . . . . . . . .   $64,251   $ 51,896
      Net loss before extraordinary item. . . . . . . . .      (689)   (11,385)
      Net loss per share before extraordinary item. . . .     (0.11)     (2.19)


(4)  IMPAIRMENT OF LONG-LIVED ASSETS

     The Company adopted FAS 121 effective as of January 1, 1995.  FAS 121 
requires that long-lived assets held and used by an entity, including oil and 
gas properties accounted for under the successful efforts method of 
accounting, be reviewed for impairment whenever events or changes in 
circumstances indicate that the carrying amount of an asset may not be 
recoverable. Long-lived assets to be disposed of are to be accounted for at 
the lower of carrying amount or fair value less cost to sell when management 
has committed to a plan to dispose of the assets.  All companies, including 
successful efforts oil and gas companies, are required to adopt FAS 121 for 
fiscal years beginning after December 15, 1995.

     In order to determine whether an impairment had occurred, the Company 
estimated the expected future cash flows of its oil and gas properties on a 
depletable unit basis and compared such future cash flows to the carrying 
amount of the related oil and gas properties to determine if the carrying 
amount was recoverable.  Based on this process, no writedown in the carrying 
amount of the Company's proved properties was necessary at December 31, 1996 
or 1995.

(5)  DERIVATIVE FINANCIAL INSTRUMENTS

     The Company utilizes derivative financial instruments to manage 
well-defined interest rate and commodity price risks.  The Company is exposed 
to credit losses in the event of nonperformance by the counterparties to its 
interest rate swap agreements and its commodity hedges.  The Company 
anticipates, however, that such counterparties will be able to fully satisfy 
their obligations under the contracts.  The Company does not obtain 
collateral or other security to support financial instruments subject to 
credit risk but monitors the credit standing of the counterparties.


                                      F-12

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    COMMODITY HEDGES.  The Company utilizes option contracts to hedge the 
effect of price changes on future oil and gas production.  If market prices 
of oil and gas exceed the strike price of put options, the options will 
expire unexercised, therefore reducing the effective price received for oil 
and gas sales by the cost of the related option.

    The following table sets forth the future volumes hedged by year and the 
weighted-average strike price of the option contracts at December 31, 1996:

                                          OIL        GAS
                                         VOLUME     VOLUME      STRIKE PRICE
                                         (BBLS)    (MMBTU)      PER BBL/MMBTU
                                        ---------  ---------  ------------------
Oil:
  1997 . . . . . . . . . . . . . . . . .1,912,500          -  $16.52 - $20.65(a)
Gas:
  1997 . . . . . . . . . . . . . . . . .        -  1,500,000      $1.65(b)

-----------------------
(a) Represents the weighted-average price of a purchased put option contract 
    and of a collar established with the purchase of a put option contract and 
    the sale of a call option contract.
(b) Represents the strike price on a purchased put option contract.

    INTEREST RATE SWAP AGREEMENTS. Prior to the Offerings, the Company 
utilized two interest rate swap agreements to reduce the potential impact of 
increases in interest rates on floating-rate long-term debt.  Concurrent with 
the issuance of the $100 million of 10.25% fixed-rate senior notes in early 
October 1996, the two interest rate swap agreements ceased to be hedges.  
These interest rate swap agreements were marked-to-market and the related 
liability recorded.  The liability for the two interest rate swap agreements 
was $1,712,000 at December 31, 1996.  The average balance of this liability 
during the quarter ended December 31, 1996 was approximately $1,700,000.  
During the quarter ended December 31, 1996, the Company recorded investment 
losses of $207,300 on the interest rate swap agreements.  The following table 
sets forth the terms, fixed rates, and notional amounts of the interest rate 
swap agreements in place as of December 31, 1996:

                                   NOTIONAL
                                   PRINCIPAL          FIXED
            TERM                    AMOUNT        INTEREST RATE
--------------------------------   -----------    -------------
 Jan. 25, 1996 to Jan. 25, 1999    $24 million        7.50%
May 24, 1995 to May 27, 1997 (a)   $60 million        5.99%

-----------------------
(a)  Subject to extension until May 24, 1999 at the option of the
counterparty.

(6)  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The following table presents the carrying amounts and estimated fair 
values of the Company's financial instruments at December 31, 1996 and 1995.  
FASB Statement No. 107, DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL 
INSTRUMENTS, defines the fair value of a financial instrument as the amount 
at which the instrument could be exchanged in a current transaction between 
willing parties.

                                       F-13

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
                                                         1996                 1995
                                                 -------------------   ----------------
                                                 CARRYING    FAIR      CARRYING   FAIR
                                                  AMOUNT     VALUE      AMOUNT    VALUE
                                                 --------   --------   -------    -----
<S>                                              <C>        <C>        <C>        <C>
Financial Assets:                                             (IN THOUSANDS)
  Cash, cash equivalents and restricted cash. . .$ 12,618   $ 12,618   $ 2,866   $ 2,866
  Receivables (trade) . . . . . . . . . . . . . .   6,675      6,675     3,154     3,154
  Receivables (oil and gas sales) . . . . . . . .   9,031      9,031     3,915     3,915 
  Commodity option contracts. . . . . . . . . . .     592     (2,172)      165       555 
  Notes receivable -- affiliate . . . . . . . . .     684        542       684       684 
  Notes receivable -- other . . . . . . . . . . .     500        500         0         0
Financial liablilites:
  Payables (trade). . . . . . . . . . . . . . . .  12,718     12,718     5,467     5,467 
  Deferred revenue. . . . . . . . . . . . . . . .       -          -     3,319     2,950 
  Long-term debt. . . . . . . . . . . . . . . . . 100,262    105,512    71,494    71,494 
  Interest rate swap and option agreements. . . .   1,712      1,712       146    (2,970)
</TABLE>

    The carrying amounts shown in the table are included in the statement of 
financial position under the indicated captions.

    The following methods and assumptions were used to estimate the fair 
value of each class of financial instruments:

    CASH, TRADE RECEIVABLES, NOTES RECEIVABLE-OTHER AND TRADE PAYABLES:  The 
carrying amounts approximate fair value because of the short maturity of 
those instruments.

    COMMODITY OPTION CONTRACTS: The carrying amount comprises the unamortized 
premiums paid for the option contracts.  The fair value is estimated using 
option pricing models and essentially values the potential for the option 
contracts to become in-the-money through changes in commodity prices during 
the remaining terms.

    NOTES RECEIVABLE-AFFILIATE:  The amounts reported relate to notes 
receivable from an affiliated company.  The carrying amount reflects an 
estimate of net present value using an assumed annual interest rate of 9% 
based upon the anticipated note payment schedule.

    DEFERRED REVENUE:  The amounts reported relate to the gas purchase 
agreements described in Note 2.  The carrying amount represents the payments 
received under the agreements for which subsequent delivery is required.  The 
fair value is estimated based upon the commodity price at December 31, 1995 
for a similar agreement.

    LONG-TERM DEBT:  The fair value of the Corporation's long-term debt is 
based upon the quoted market price for this issue at December 31, 1996.

    INTEREST RATE SWAP AGREEMENTS:  At December 31, 1996, the Company had two 
interest rate swap agreements outstanding with an aggregate notional amount 
of $84 million.  These agreements are more fully described in Note 5.  The 
carrying amount is equal to the sum of the unamortized premiums paid for the 
agreements and the fair value.  The fair values of each of the open interest 
rate swap agreements were obtained from bank quotes and represent the 
estimated amount the Company would pay upon termination of the agreements at 
December 31, 1996, taking into consideration interest rates at that date. 

                                       F-14

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(7)  LONG-TERM DEBT

Long-term debt consists of the following (thousands):

                                               DECEMBER 31,
                                            -------------------
                                              1996       1995  
                                            --------   -------
     10 1/4% Senior Notes due 2006 . . . . .$100,000   $     - 
     Revolver Note . . . . . . . . . . . . .     100    59,824 
     Term notes. . . . . . . . . . . . . . .       -    11,670 
     Other notes payable . . . . . . . . . .     260         - 
                                            --------  -------- 
                                             100,360    71,494 
            Less current maturities. . . . .      98         - 
                                            --------  -------- 
                                            $100,262  $ 71,494 
                                            --------  -------- 
                                            --------  -------- 

    In October 1996, the Company issued $100 million aggregate principal 
amount of 10.25% Senior Notes due October 1, 2006 (the "Notes").  The notes 
were sold at par and interest is payable April 1 and October 1, commencing 
April 1, 1997.  The Notes may not be redeemed prior to October 1, 2001, and 
thereafter at a premium reducing to par, plus interest, by maturity.  There 
is no mandatory redemption of the Notes required prior to maturity. The notes 
are general unsecured senior obligations of the Company and rank equally in 
right of payment with all other senior indebtedness of the Company and senior 
in right of payment of all existing future subordinated indebtedness of the 
Company. The Notes are subject to an Indenture between the Company and a 
trustee.  The Indenture restricts, among other things, the Company's ability 
to incur additional indebtedness, pay dividends or make certain other 
restricted payments, incur liens, engage in any sale and leaseback 
transaction, sell stock of subsidiaries, apply net proceeds from certain 
assets sales, merge or consolidate with any other person, sell, assign, 
transfer, lease, convey or otherwise dispose of substantially all of the 
assets of the company, or enter into certain transactions with affiliates. 
Net proceeds from the sale of the Notes of approximately $96.1 million were 
used to repay existing indebtedness.

    In October 1996, the Company entered into a credit agreement (the "1996 
Credit Facility") with NationsBank of Texas, N.A. (the "Bank").  The 1996 
Credit Facility provides a revolving line of credit with the availability of 
funds and letters of credit being subject to a borrowing base determination 
at least semiannually. The borrowing base provides a maximum availability of 
$50.0 million (which amount is also the initial borrowing base), $100,000 of 
which was outstanding at December 31, 1996. Availability under the borrowing 
base is initially limited to $20.0 million for working capital and $30.0 
million for acquisitions of oil and gas properties meeting certain criteria 
established by the Bank.  Borrowings under the 1996 Credit Facility bear 
interest, at the Company's option, at a floating rate which is at or above 
the NationsBank, N.A. prime rate or the LIBOR rate, depending on the 
percentage of committed funds which have been borrowed.  Interest is payable 
quarterly and principal will be amortized in twelve equal installments 
commencing two years from the date of the credit agreement.  Under the 1996 
Credit Facility, the Company is obligated to pay certain fees to the Bank, 
including a commitment fee which ranges from 0.30% to 0.40% based on 
the unused portion of the commitment. The 1996 Credit Facility contains 
customary restrictive covenants (including restrictions on the payment of 
dividends and the incurrence of additional indebtedness) and requires the 
Company to maintain a current ratio of not less than 1.0 to 1.0, a ratio of 
Adjusted EBITDA to interest expense of not less than 2.0 to 1.0 and a minimum 
tangible net worth.  Borrowings under the 1996 Credit Facility are secured by 
substantially all of the assets of the Company and any subsidiary of the 
Company that guarantees the Company's obligations under the 1996 Credit 
Facility.  Initially, none of the Company's subsidiaries have guaranteed the 
Company's obligations under the 1996 Credit Facility.

    In June, 1996, the Company entered into a loan agreement with 
NationsBridge, L.L.C. to provide financing of up to $125 million ("Bridge 
Loan").  The proceeds of this Bridge Loan were used to finance the 1996 
Acquisition, to refinance the 1995 Credit Facility and for other general 
corporate purposes.  The Company 



                                      F-15

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


capitalized certain costs incurred in obtaining the Bridge Loan and amortized 
these costs over the estimated life of the Bridge Loan.  Concurrent with the 
Offerings, the $2,665,000 remaining unamortized balance of these deferred 
charges were expensed as an extraordinary item.

    In June, 1995, the Company entered into a Credit Agreement ("1995 Credit 
Facility") with a syndicate of banks to provide financing for an aggregate 
$185 million senior secured revolving line of credit ("Revolver Notes") and 
an aggregate $15 million in senior secured term notes ("Term Notes").  In 
June 1996, these notes in a total amount of $71,494,000 were paid off with a 
portion of the proceeds of the Bridge Loan.  The Company capitalized certain 
costs incurred in obtaining the 1995 Credit Facility and amortized these 
costs over the lives of the notes.  Concurrent with the Bridge Loan, the 
$1,640,000 remaining unamortized balance of these deferred charges were 
expensed as an extraordinary item.

    Maturities of long-term debt at December 31, 1996 are as follows 
(thousands):

     1997 . . . . . . . . . . . . . . . . . . $     98 
     1998 . . . . . . . . . . . . . . . . . .       62 
     1999 . . . . . . . . . . . . . . . . . .      101 
     2000 . . . . . . . . . . . . . . . . . .        - 
     2001 . . . . . . . . . . . . . . . . . .      100 
     Thereafter  . . . . . . . . . . . . . . . 100,000 

    The Company paid interest on long-term debt of $8,838,971, $4,453,684 and 
$1,356,604 in 1996, 1995 and 1994, respectively.

(8) INCOME TAXES

    Concurrent with the Offerings and upon consummation of the Corporate 
Reorganization, the Company became a tax paying entity for U.S. Federal 
income tax purposes.  At that date, the tax basis of the Company's assets and 
liabilities exceeded the book basis by approximately $3,500,000, resulting in 
a deferred tax asset of approximately $1,200,000.  A valuation allowance was 
provided for 100% of this deferred tax asset.

    Income tax provision (benefit), generated from $2,978,000 of net income 
before extraordinary item from the date of the Corporate Reorganization 
through December 31, 1996, and amounts separately allocated were 
as follows (thousands):

         Income (loss) before extraordinary item   $  1,218 
         Extraordinary loss resulting from early
           extinguishment of debt                    (1,042)
                                                   --------
                                                   $    176 
                                                   --------
                                                   --------

    The Company's effective tax rate does not differ materially from the U.S. 
Federal statutory rate.

                                       F-16


<PAGE>

                       COSTILLA ENERGY, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The tax effects of temporary differences that give rise to significant 
portions of deferred tax assets and deferred tax liabilities were as follows 
at December 31, 1996:

     Deferred tax assets:
       Net operating loss carryforwards                     $ 2,805 
       Interest rate swap agreements held
        for trading purposes                                    599 
                                                            -------
         Total gross deferred tax asset                       3,404 
                                                            -------
     Deferred tax liabilities:
       Oil and gas properties, principally due
        to differences in depletion and the 
        deduction of intangible drilling costs
        for tax purposes                                      1,692 
                                                            -------

     Net deferred tax asset                                   1,712 
     Valuation allowance of net deferred tax asset           (1,712)
                                                            -------
     Net deferred tax asset, net of valuation allowance     $     - 
                                                            -------
                                                            -------

     A valuation is provided for when it is more likely than not that some 
portion of the deferred tax assets will not be realized.  Due to uncertainties 
arising from a lack of earnings history and based on management's intentions 
to continue an aggressive drilling program (generating intangible drilling 
costs which are projected to create future losses for tax purposes), it does 
not appear more likely than not that the Company will be able to utilize all 
the available carryforwards prior to their ultimate expiration.

     At December 31, 1996, the Company had net operating loss carryforwards of 
approximately $8 million, which are available to offset future regular taxable 
income, if any.  The carryforwards expire December 31, 2011.

(9)  COMMITMENTS AND CONTINGENCIES

     LEASES

     The Company leases equipment and office facilities under operating leases 
on which rental expense for the years ended December 31, 1996, 1995 and 1994 
was $416,442, $311,221, and $197,533, respectively. Future minimum lease 
commitments under noncancellable operating leases at December 31, 1996 are as 
follows (thousands):

     1997...................................   $  275,695 
     1998...................................      273,943 
     1999...................................      260,324 
     2000...................................      233,880 
     2001...................................      286,850 
     Thereafter.............................    1,395,886 

     EMPLOYMENT AGREEMENTS

     During the period from June through October, 1996, the Company entered 
into employment agreements with four of its executive officers.  The 
employment agreements are each for three years and each will automatically 
renew for successive one-year periods thereafter unless the employee is 
notified to the contrary. These employment agreements provide for base annual 
salary levels totaling $990,000 for 1997.

                                     F-17
<PAGE>

                       COSTILLA ENERGY, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Each employee would receive his salary for the remaining term of the 
applicable employment agreement if the Company were to terminate such person's 
employment other than for cause.  If such person were to voluntarily leave his 
employment with the Company prior to the second anniversary of the employment 
agreement no further payments would be required.  With the exception of one of 
the Company's executive officers, if a voluntary termination were to occur 
after the second anniversary of the employee agreement, such person would be 
entitled to one year's salary from the date of termination. With the exception 
of one of the Company's executive officers, the employee agreements provide 
that the covered employee will not compete with the Company for a one year 
period following his voluntary cessation of employment or termination of 
employment for cause, in either case if such event occurs within the initial 
three-year term of the employee agreement.

EXPLORATION AND DEVELOPMENT

     In July 1995, the Republic of Moldova (located in Eastern Europe between 
Romania and the Ukraine) granted a Concession Agreement to Resource 
Development Company Limited, L.L.C. ("Redeco"), an entity not affiliated with 
the Company.  The Company paid Redeco $90,000 and agreed to bear the first 
$2.0 million of Concession expenses in return for a 50.0% interest in Redeco.  
Upon reaching the $2.0 million in 1996, Redeco elected, according to the 
agreement, to pay the Company for half of all amounts expended in excess of 
$750,000 plus interest.  The Concession Agreement covers the entire country 
with respect to oil and gas and other minerals and continues for various time 
periods depending on the nature of the activity conducted.  The Company has no 
material fixed financial commitments with respect to the Concession.  As of 
December 31, 1996, the Company's share of costs expended was $1,909,349.

     LETTERS OF CREDIT

     As a result of certain bonding and trade creditor requirements, the 
Company has caused irrevocable letters of credit to be issued by a bank 
totaling $96,000.  As of December 31, 1996, no amounts had been drawn on these 
letters of credit.

(10) 401(k) PLAN

     The Company has established a qualified cash or deferred arrangement 
under IRS code section 401(k) covering substantially all employees.  Under the 
plan, the employees have an option to make elective contributions of a portion 
of their eligible compensation, not to exceed specified annual limitations, to 
the plan and the Company has an option to match a percentage of the employee's 
contribution.  The Company has made matching contributions to the plan 
totaling  $58,713, $22,531, and $8,921 in 1996, 1995 and 1994, respectively.

(11) REDEEMABLE PREDECESSOR CAPITAL AND PREDECESSOR CAPITAL

     During 1995, NationsBanc Capital Corporation ("NBCC") contributed $10 
million in exchange for a 30% ownership interest in the Company including the 
preferential return described below.  Of this amount $1,266,000 was attributed 
to the non-redeemable portion of predecessor capital and $8,734,000 was 
attributed to redeemable predecessor capital.  Preferred return and accretion 
of predecessor capital included in the consolidated statements of operations 
and the consolidated statements of stockholders' equity includes accretion of 
the amount attributable to redeemable predecessor capital to $10,000,000 over 
a two year period beginning February 17, 1995.  As described below, the 
redemption amount was ultimately to be equal to $10,000,000 plus a preferred 
return and an additional redemption amount related to NBCC's redeemable 
interest not subject to preferential return.

     Concurrent with the Offerings, NBCC's membership interest was redeemed 
for a total of $15,506,614 and 936,000 common shares were issued to NBCC.  
After accounting for the Underwriter's exercise of its over-

                                     F-18
<PAGE>

                            COSTILLA ENERGY, INC.

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

allotment option in November 1996, NBCC owns 8.94% of the 10,475,000 common 
shares outstanding at December 31, 1996.  The following table details the 
redemption price paid to NBCC:

     NBCC Preferred Capital Contribution.................   $10,000,000 
     Preferred Return....................................     2,732,376 
                                                            -----------
     Adjusted NBCC Preferred Capital Contribution........    12,732,376 
     
     PLUS: 10% Redemption Premium........................     1,273,238 
     PLUS: Aggregate Redemption Price of NBCC's   
           Redeemable Unrestricted Common Units..........     1,500,000 
                                                            -----------
     Total Redemption Price Paid NBCC....................   $15,505,614 
                                                            -----------
                                                            -----------

     Redeemable predecessor capital was subject to a preferential return of 
15% per annum and was redeemable at any time at the Company's option, subject 
to a redemption premium as described below, or at NBCC's option on February 
17, 2003 or at an earlier date upon occurrence of certain events including a 
change in control, certain changes in management, a change in the Company's 
status as a limited liability company for tax purposes, or violation of any of 
various other restrictive provisions contained in the Regulations of Costilla 
Energy, Inc. (the "Regulations").  The 15% preferred return was treated as a 
reduction of predecessor capital.  The redemption price to be paid by the 
Company was equal to the initial amount received for the preferred units plus 
a premium, determined in the year the units are purchased, as follows:

       Year after               Premium
   February 17, 1995          Percentage
   -----------------          ----------
           1                      10%
           2                      10%
           3                      8%
           4                      6%
           5                      4%
           6                      2%
           7                      0%
           8                      0%

     In addition, a portion of NBCC's interest not subject to preferential 
return was classified as redeemable predecessor capital as the Company could 
have been be required to repurchase such interest upon the occurrence of 
certain events similar to those events requiring redemption of the redeemable 
predecessor capital described above and, in any event, on or after February 
17, 2000.  Such interest could have, at the Company's option, been repurchased 
to the extent the Company has exercised its right to redeem all or a portion 
of the redeemable members' interest subject to the preferential return.  The 
redemption price the Company would have paid in either instance would be 
determined by the year in which the predecessor capital was repurchased as 
follows:

                   Before                Aggregate 
                 February 17           Redemption Price
                 -----------           ----------------
                    1996                 $        1 
                    1997                  1,500,000 
                    1998                  3,000,000 
                    1999                  4,500,000 
                    2000                  5,500,000 

                                     F-19
<PAGE>

                            COSTILLA ENERGY, INC.

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Prior to the Offerings in October 1996, the ultimate redemption price of 
$5,500,000 was being accrued ratably over the period from February 17, 1995 
through February 17, 2000 and was treated as a reduction of predecessor 
capital.

(12) STOCK-BASED COMPENSATION

     OUTSIDE DIRECTORS STOCK OPTION PLAN

     The Outside Directors Stock Option Plan provides for the issuance of 
stock options to the outside directors of the Company.  A total of 50,000 
shares has been authorized and reserved for issuance under the plan, subject 
to adjustments to reflect changes in the Company's capitalization resulting 
from stock splits, stock dividends and similar events.  Only outside directors 
are eligible to participate in the plan.  Outside directors are those 
directors of the Company who are not executive officers or regular salaried 
employees of the Company as of the date the Option is granted.  Under the 
plan, an option for 1,000 shares of Common Stock will be granted to each 
person who qualifies as an outside director each year that such person is 
elected as a director of the Company.  The exercise price of each option 
granted under the plan will be the fair market value (as reported on the 
Nasdaq National Market) of the Common Stock at the time the option is granted 
and may be paid either in cash, shares of Common Stock or a broker-assisted 
cashless transaction.  Each option will be exercisable immediately, and will 
expire ten years from the date of grant.  As of December 31, 1996, no options 
had been granted under this plan. 

     BONUS INCENTIVE PLAN

     The Company has adopted the Bonus Incentive Plan, concurrent with the 
Offerings.  The plan provides that the Board of Directors each year may award 
bonuses in cash, Common Stock, or some combination thereof, to those officers, 
directors, employees and advisors of the Company or a subsidiary of the 
Company, who the Board of Directors determines have contributed to the success 
of the Company.  A total of 150,000 shares of Common Stock has been authorized 
and reserved for issuance under the plan, subject to adjustments to reflect 
changes in the Company's capitalization resulting from stock splits, stock 
dividends and similar events.  All officers, directors, employees and advisors 
of the Company or a subsidiary of the Company who have completed a minimum of 
180 days of service and are employed or retained by the Company or such 
subsidiary on the last day of the plan year, other than such persons who own 
ten percent or more of the outstanding shares of the Common Stock during that 
year, are eligible to participate in the plan.  Bonus awards will be 
determined based upon a number of factors, including performance and salary 
level of the participant and the financial performance of the Company and its 
subsidiaries.  Bonuses will be awarded after review and upon approval of the 
Board of Directors, subject to the terms and conditions of the plan.  As of 
December 31, 1996, no shares of Common Stock have been issued pursuant to this 
plan.

     1996 STOCK OPTION PLAN

     The 1996 Stock Option Plan provides for the grant of both incentive stock 
options and non-qualifying stock options, as well as limited stock 
appreciation rights and supplemental bonuses, to the employees of the Company 
and its subsidiaries, including officers and  directors who are salaried 
employees. A total of 850,000 shares of Common Stock has been authorized and 
reserved for issuance under the plan, subject to adjustments to reflect 
changes in the Company's capitalization resulting from stock splits, stock 
dividends and similar events.  The plan is administered by the Board of 
Directors.  The Board of Directors has the sole authority to interpret the 
plan, to determine the persons to whom the options will be granted, to 
determine the basis upon which the options will be granted, and to determine 
the exercise price, duration and other terms of the options to be granted 
under the plan; provided that (a) the exercise price of each option granted 
under the plan may not be less than the fair market value of the Common Stock 
on the date the option is granted (and for incentive stock options, 110% of 
fair market value if the employee is the beneficial owner of 10% or more the 
Company's voting securities), (b) the exercise price must be paid in cash, by 
surrendering previously owned shares of Common Stock upon the exercise of the 
option or by a

                                     F-20
<PAGE>

                            COSTILLA ENERGY, INC.

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

promissory note or broker-assisted cashless exercise approved by the Board of 
Directors, (c) the term of the option may not exceed ten years, and (d) no 
option is transferable other than by will, the laws of descent and 
distribution or pursuant to a qualified domestic relations order.  Limited 
stock appreciation rights may be granted under the plan with respect to 
specified options, allowing the option holder to receive, in cash, the 
difference between the exercise price and the market value in the event of a 
change in control of the Company.  The Board of Directors may also grant 
supplemental bonuses under the plan which are cash bonuses not to exceed the 
amount of income tax liability incurred by a plan participant upon the 
exercise of a non-qualifying stock option or a limited stock appreciation 
right with respect to which the bonus was granted.  The Board of Directors may 
amend without stockholder approval, in any respect other than any amendment 
that requires stockholder approval by law, and may modify any outstanding 
option, including the repricing of non-qualifying options, with the consent of 
the option holder.  There are currently approximately 100 employees who are 
eligible to participate in the plan.

     During 1996, the Company granted 711,750 stock options pursuant to the 
1996 Stock Option Plan, leaving 138,250 options available for future grant 
under the plan as of December 31, 1996.  The options granted during the year 
have a term of ten (10) years and an exercise price of $12.50 per share, a 
price equal to the market price on the date of the grant.  The fair value, as 
calculated under the provision of SFAS 123, of the options granted in 1996 was 
$6.73 per share.

     The Company applies APB 25 and related Interpretations in accounting for 
its stock option awards.  Accordingly, no compensation expense has been 
recognized for its stock option awards.  If compensation expense for the stock 
option awards had been determined consistent with SFAS 123, the Company's net 
loss and net loss per share, for the year ended December 31, 1996 would have 
been adjusted to the following pro forma amounts:

                     Net loss                  $(6,285,276)

                     Net loss per share        $     (0.97)

     The pro forma net loss and pro forma net loss per share amounts noted 
above are not likely to be representative of the pro forma amounts to be 
reported in future years.  Pro forma adjustments in future years will include 
compensation expense associated with the options granted in 1996 plus 
compensation expense associated with any options awarded in future years.  As 
a result, such pro forma compensation expense is likely to be higher than the 
levels reflected for 1996 if any options are awarded in future years.

     Under SFAS 123, the fair value of each stock option grant is estimated on 
the date of grant using the Black-Scholes option pricing model with the 
following weighted average assumptions used for grants in 1996:

       Risk-free interest rate           6.25%
       Expected life                   5 years
       Expected volatility                 54%
       Expected dividend yield              0%

(13) RELATED PARTY TRANSACTIONS

     Certain members and officers of the Company own interests in and hold 
positions with A&P Meter Service and Supply, Inc. ("A&P"), CSL, 511 Tex L.C. 
("511 Tex"), and Valley.

     Advances from the Company to A&P have been consolidated into two 
promissory notes.  The first note, which was originally executed December 31, 
1994, totals $390,000, including accrued interest of $20,000 at December 31, 
1996.  The note bears interest at a floating rate equal to the "prime rate" 
plus 1.0%.  No principal or interest payments are due until the maturity of 
the note at December 31, 2004.  The note is secured by a second lien on A&P's 
accounts receivable, inventory and equipment.  The second note is in the 
amount of $294,000,

                                     F-21

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


including accrued interest of $47,000, and is dated May 22, 1996.  The note 
bears interest at 6.0% per annum, is unsecured and is payable upon demand.  
During 1996, the Company paid $520,519 to A&P for goods and services 
provided. During 1995, the Company paid $612,139 to A&P for goods and 
services provided.

     During 1996, 1995 and 1994, the Company paid $517,352, $592,920 and 
$549,620, respectively, to CSL for management fees and lease payments on 
equipment.

     During 1996, the Company paid $50,742 to 511 Tex for office rent. During 
1995, the Company paid $67,896 to 511 Tex for office rent.

     During 1996, 1995 and 1994 the Company paid $484,000, $440,884 and 
$2,458, respectively, to Valley for gas compression and salt water disposal 
charges.  During 1996, Valley paid the Company $383,139 for operating costs 
of its salt water disposal wells and gas compressors.  During 1995, Valley 
paid the Company $109,399 for operating costs of its salt water disposal 
wells and gas compressors.

     On December 31, 1996, certain officers and related party entities owed 
the Company $321,310 plus accrued interest of $1,431. During March 
1997, the Company has received full payment for these amounts. 


     During 1996 and 1995 the LLC paid $75,000 each year to NationsBank 
Capital Corp. for management fees.  No management fees are due to NationsBank 
Capital Corp. for any period subsequent to the Offerings.

(14) SUBSEQUENT EVENTS

     On January 1, 1997 Costilla Petroleum Corporation was merged into its 
parent, Costilla Energy, Inc. and Costilla Energy, Inc. assumed the business, 
assets and liabilities of Costilla Petroleum Corporation.  The merger was 
effected for administrative purposes and to further reflect the Corporate 
Reorganization whereby business will be conducted through the Company rather 
than its predecessor, Costilla Energy, L.L.C.

     On March 1, 1997 Valley Gathering Company was merged into its parent, 
Costilla Energy, Inc. and Costilla Energy, Inc. assumed the business, assets 
and liabilities of Valley Gathering Company.  The merger was effected for 
administrative purposes and to further reflect the Corporate Reorganization 
whereby business will be conducted through the Company rather than its 
predecessor, Costilla Energy, L.L.C.

     On March 5, 1997 Statewide was dissolved.  This dissolution was effected 
for administrative purposes subsequent to the sale on December 31, 1996 of 
substantially all of the assets of Statewide for net proceeds of 
approximately $3.0 million.  The remaining unsold producing oil and gas 
property was transferred to its parent, Costilla Energy, Inc., on December 
31, 1996.

     On March 6, 1997, the Company sold its 40.5% interest in a Delaware 
limited liability company which owns and operates a gas pipeline and 
associated facilities in Louisiana.  This membership interest had been held 
for resale.  The Company sold its interest to another member of the limited 
liability company for $1,071,150.  This amount represented the Company's 
actual investment of $1,019,771 plus interest of $51,379 since the date of 
the Company's original investment in April, 1996.  The effective date of the 
sale was the date of the Company's original investment in April, 1996.  The 
Company received a cash payment of $918,184 on March 6, 1997.  In addition, 
the Company received a $152,966 note due in full on July 1, 1997 plus 
interest at 5.62%.


                                     F-22

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(15)  OIL AND GAS EXPENDITURES

     The following table reflects costs incurred in oil and gas property 
acquisition, exploration and development activities:

                                            YEARS ENDED DECEMBER 31,
                                         ------------------------------
                                           1996       1995        1994
                                         -------    -------     -------
                                                  (THOUSANDS)
    Property acquisition costs:
      Proved                             $39,505    $52,470     $ 9,649
      Unproved                               721      1,742       1,232
    Exploration                            6,760      5,627       2,167
    Development                           17,723        158           -
                                         -------    -------     -------

                                         $64,709    $59,997     $13,048
                                         -------    -------     -------
                                         -------    -------     -------



(16) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

     The estimates of proved oil and gas reserves, which are located 
principally in the United States, were prepared by the Company as of December 
31, 1995 and 1994 and by Williamson Petroleum Consultants as of December 31, 
1996.  Reserves were estimated in accordance with guidelines established by 
the SEC and FASB which require that reserve estimates be prepared under 
existing economic and operating conditions with no provision for price and 
cost escalations except by contractual arrangements.  The Company has 
presented the reserve estimates utilizing an oil price of $24.17 per Bbl and 
a gas price of $3.96 per Mcf as of December 31, 1996 and an oil price of 
$17.79 per Bbl and a gas price of $2.03 per Mcf as of December 31, 1995.

     OIL AND GAS PRODUCING ACTIVITIES

     Oil and gas reserve quantity estimates are subject to numerous 
uncertainties inherent in the estimation of quantities of proved reserves and 
in the projection of future rates of production and the timing of development 
expenditures.  The accuracy of such estimates is a function of the quality of 
available data and of engineering and geological interpretation and judgment. 
Results of subsequent drilling, testing and production may cause either 
upward or downward revision of previous estimates.  Further, the volumes 
considered to be commercially recoverable fluctuate with changes in prices 
and operating costs.  The Company emphasizes that reserve estimates are 
inherently imprecise and that estimates of new discoveries are more imprecise 
than those of currently producing oil and gas properties.  Accordingly, these 
estimates are expected to change as additional information becomes available 
in the future.


                                      F-23

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                                      OIL AND         NATURAL 
                                                CONDENSATE (MBBLS)   GAS (MMCF)
                                                ------------------   ----------
Total Proved Reserves:
Balance, January 1, 1993 . . . . . . . . . . . .      1,985            16,418
  Revisions of previous estimates  . . . . . . .         57             1,160
  Extensions and discoveries . . . . . . . . . .        380               591
  Production . . . . . . . . . . . . . . . . . .       (158)             (865)
  Purchases of minerals-in-place . . . . . . . .        101             4,315 
                                                     ------           -------

Balance, December 31, 1993 . . . . . . . . . . .      2,365            21,619 
  Revisions of previous estimates  . . . . . . .       (460)           (5,424)
  Extensions and discoveries . . . . . . . . . .        761             1,520 
  Production . . . . . . . . . . . . . . . . . .       (330)           (1,600)
  Purchases of minerals-in-place . . . . . . . .      1,673            11,397 
                                                     ------           -------
                                                                  
Balance, December 31, 1994 . . . . . . . . . . .      4,009            27,512 
  Revisions of previous estimates  . . . . . . .       (570)              425 
  Extensions and discoveries . . . . . . . . . .        605             8,922 
  Production . . . . . . . . . . . . . . . . . .       (950)           (4,806)
  Purchases of minerals-in-place . . . . . . . .      7,694            46,099 
                                                     ------           -------
                                                                  
Balance, December 31, 1995 . . . . . . . . . . .     10,788            78,152 
  Revisions of previous estimates  . . . . . . .      1,782             5,440 
  Extensions and discoveries . . . . . . . . . .      1,169            13,581 
  Production . . . . . . . . . . . . . . . . . .     (1,726)           (9,205)
  Sales of minerals-in-place . . . . . . . . . .       (119)             (482)
  Purchases of minerals-in-place . . . . . . . .      5,106            32,786 
                                                     ------           -------

Balance, December 31, 1996   . . . . . . . . . .     17,000           120,272 
                                                     ------           -------
                                                     ------           -------
Proved Developed Reserves:
  January 1, 1993. . . . . . . . . . . . . . . .      1,488            10,055 
  December 31, 1993. . . . . . . . . . . . . . .      1,785            13,268 
  December 31, 1994. . . . . . . . . . . . . . .      2,632            16,340 
  December 31, 1995. . . . . . . . . . . . . . .      8,566            57,393 
  December 31, 1996. . . . . . . . . . . . . . .     14,018            90,023 



                                       F-24

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
      TO PROVED OIL AND GAS RESERVES

     The standardized measure of discounted future net cash flows is computed 
by applying year-end prices of oil and gas (with consideration of price 
changes only to the extent provided by contractual arrangements) to the 
estimated future production of proved oil and gas reserves less estimated 
future expenditures (based on year-end costs) to be incurred in developing 
and producing the proved reserves, less estimated future income tax expenses 
(based on year-end statutory tax rates, with consideration of future tax 
rates already legislated) to be incurred on pretax net cash flows less tax 
basis of the properties and available credits, and assuming continuation of 
existing economic conditions.  The estimated future net cash flows are then 
discounted using a rate of 10% per year to reflect the estimated timing of 
the future cash flows.

     Discounted future cash flow estimates like those shows below are not 
intended to represent estimates of the fair value of oil and gas properties.  
Estimates of fair value should also consider probable reserves, anticipated 
future oil and gas prices, interest rates, changes in development and 
production costs and risks associated with future production.  Because of 
these and other considerations, any estimate of fair value is necessarily 
subjective and imprecise.

<TABLE>
                                                                    YEARS ENDED DECEMBER 31,
                                                              -----------------------------------
                                                                 1996         1995         1994
                                                              ---------    ---------     --------
                                                                          (THOUSANDS)
        <S>                                                     <C>            <C>         <C>
     Future cash flows . . . . . . . . . . . . . . . . . . .  $ 887,100    $ 350,653     $122,098
     Future costs:
       Production. . . . . . . . . . . . . . . . . . . . . .   (323,288)    (145,510)     (46,345)
       Development . . . . . . . . . . . . . . . . . . . . .    (25,469)     (16,806)      (7,157)
                                                              ---------    ---------     --------

     Future net cash flows before income taxes . . . . . . .    538,343      188,337       68,596
     Future income taxes . . . . . . . . . . . . . . . . . .    144,836            -            -
                                                              ---------    ---------     --------
     Future net cash flows . . . . . . . . . . . . . . . . .    393,507      188,337       68,596
     10% annual discount for estimated timing of 
      cash flows . . . . . . . . . . . . . . . . . . . . . .   (165,273)     (75,041)     (31,817)
                                                              ---------    ---------     --------
     Standardized measure of discounted net cash 
      flows. . . . . . . . . . . . . . . . . . . . . . . . .  $ 228,234    $ 113,296     $ 36,779
                                                              ---------    ---------     --------
                                                              ---------    ---------     --------
</TABLE>





                                       F-25

<PAGE>

                            COSTILLA ENERGY, INC.

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM 
      PROVED RESERVES (IN THOUSANDS)

<TABLE>
                                                                 YEARS ENDED DECEMBER 31,
                                                              -----------------------------
                                                                1996       1995       1994
                                                              --------   --------   -------
                                                                        (THOUSANDS)
        <S>                                                     <C>         <C>       <C>
     Increase (decrease):
       Purchase of minerals-in place . . . . . . . . . . . .  $ 49,966   $ 77,343   $15,231 
       Extensions and discoveries and improved
        recovery, net of future production and
        development costs. . . . . . . . . . . . . . . . . .    25,910      9,799     4,072 
       Accretion of discount . . . . . . . . . . . . . . . .    11,330      3,678     2,638 
       Net change in sales prices net of production
        costs. . . . . . . . . . . . . . . . . . . . . . . .   108,160     (3,422)      503 
       Changes in estimated future
        development costs. . . . . . . . . . . . . . . . . .     4,187     (2,419)      940 

       Revisions of quantity estimates . . . . . . . . . . .    29,485     (2,855)   (7,248)
       Net change in income taxes. . . . . . . . . . . . . .   (83,570)         -         - 
       Sales, net of production costs. . . . . . . . . . . .   (32,146)   (11,338)   (5,286)
       Sales of minerals in place. . . . . . . . . . . . . .    (1,330)         -         - 
       Changes of production rates (timing) and
        other. . . . . . . . . . . . . . . . . . . . . . . .     2,946      5,731      (448)
                                                              --------   --------   -------

         Net increase. . . . . . . . . . . . . . . . . . . .   114,938     76,517    10,402 

       Standardized measure of discounted future
        net cash flows:
          Beginning of period. . . . . . . . . . . . . . . .   113,296     36,779    26,377 
                                                              --------   --------   -------
          End of period. . . . . . . . . . . . . . . . . . .  $228,234   $113,296   $36,779 
                                                              --------   --------   -------
                                                              --------   --------   -------
</TABLE>


     The 1996 future cash flows shown above include amounts attributable to 
proved undeveloped reserves requiring approximately $24.6 million of future 
development costs.  If these reserves are not developed, the standardized 
measure of discounted future net cash flows for 1996 shown above would be 
reduced by approximately $44.4 million.






                                      F-26



<PAGE>

                               EXHIBIT INDEX

Exhibit
 Number         Description of Exhibit
-------         ----------------------
  *3.1      Certificate of Incorporation of the Company
  *3.2      Bylaws of the Company
  *4.1      Form of Notes or Global Certificate (included as Exhibit A to the
            Indenture)
  *4.2      Indenture dated as of October 1, 1996 by and between State Street
            Bank and Trust Company, as Trustee, and the Company, as Issuer
 **4.3      Form of Stock Certificate
***10.1     Credit Agreement dated October 10, 1996 between NationsBank of
            Texas, N.A., as agent, the Lenders named therein and the Company
  *10.2     Lease Agreement dated January 12, 1996 between Independence
            Plaza, Ltd. and Costilla Energy, L.L.C.
  *10.3     Concession Agreement dated July 6, 1995 between the Government of
            the Republic of Moldova and Resource Development Company Ltd.,
            L.L.C. (DE)
  *10.4     Consolidation Agreement dated October 8, 1996
  *10.5     1996 Stock Option Plan
  *10.6     Outside Directors Stock Option Plan
  *10.7     Employment Agreement between the Company and Bobby W. Page
            effective June 30, 1996
  *10.8     Employment Agreement between the Company and Cadell S. Liedtke
            effective October 8, 1996
  *10.9     Employment Agreement between the Company and Michael J. Grella
            effective October 8, 1996
  *10.10    Employment Agreement between the Company and Henry G. Musselman
            effective October 8, 1996
  *10.11    Purchase and Sale Agreement dated April 3, 1995 by and between
            Parker & Parsley Development L.P., Parker & Parsley Producing
            L.P. and Parker & Parsley Gas Processing Co., as Seller, and
            Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
            Purchaser
  *10.12    Purchase and Sale Agreement dated March 8, 1996 by and between
            Parker & Parsley Development L.P., Parker & Parsley Producing
            L.P. and Parker & Parsley Gas Processing Co., as Seller, and
            Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
            Purchaser
  *10.13    Bonus Incentive Plan
***10.14    Letter Agreement dated December 18, 1996 by and between Statewide
            Minerals, Inc., as Seller, Boldrick Partners, as Buyer

<PAGE>

Exhibit
 Number         Description of Exhibit
-------         ----------------------
***10.15    Stock Purchase Agreement dated December 31, 1996 by and between ERI
            Investments, Inc. and the Company
***12.1     Computation of Ratio of Adjusted EBITDA to Interest Expense
 **16.1     Letter Regarding Change of Accountants
***21.1     Subsidiaries of the Registrant
***23.1     Consent of KPMG Peat Marwick LLP
***23.2     Consent of Williamson Petroleum Consultants, Inc.
***23.3     Consent of Elms, Faris & Co., P.C.
***24.1     Power of Attorney
***24.2     Certified copy of resolution of Board of Directors of Costilla
            Energy, Inc. authorizing signature by Power of Attorney
***27.1     Financial Data Schedule

-------------------
*    Incorporated by reference to Registration Statement on Form S-1, File
     No. 333-08909
**   Incorporated by reference to Registration Statement on Form S-1, File
     No. 333-08913.
***  Filed herewith