<PAGE>   1

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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, 1997

                                       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   X   NO       
                                  -----    ------

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

The aggregate market value of the Common Stock held by non-affiliates, based
upon the last sale price as quoted on the Nasdaq Stock Market's National Market
of $10.38 per share on March 24, 1998 was $55,819,280.

Number of shares of Common Stock outstanding as of March 24, 1998..... 9,981,000

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, 1998 and which is incorporated herein by
reference.

================================================================================




<PAGE>   2



                             COSTILLA ENERGY, INC.

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>


                                                                                                 Page
                                                                                                 ----
PART I .

<S>               <C>                                                                            <C>
Item 1.           Business.                                                                         3

Item 2.           Properties.                                                                      10

Item 3.           Legal Proceedings.                                                               16

Item 4.           Submission of Matters to a Vote of Security Holders.                             16

PART II.

Item 5.           Market for the Registrant's Common Equity and
                  Related Stockholder Matters.                                                     17

Item 6.           Selected Financial Data.                                                         18

Item 7.           Management's Discussion and Analysis of Financial
                  Condition and Results of Operations.                                             19

Item 8.           Financial Statements and Supplementary Data.                                     27

Item 9.           Changes in and Disagreements with Accountants on Accounting and
                  Financial Disclosure.                                                            27

PART III.

Item 10.          Directors and Executive Officers of the Registrant.                              28

Item 11.          Executive Compensation.                                                          28

Item 12.          Security Ownership of Certain Beneficial Owners and Management.                  28

Item 13.          Certain Relationships and Related Transactions.                                  28

PART IV.

Item 14.          Exhibits, Financial Statement Schedules and Reports on Form 8-K.                 29

SIGNATURES                                                                                         32

</TABLE>


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                                     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
may be deemed to be "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933, as amended (the "Securities Act"), and
Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"). All statements, other than statements of historical facts, included in
this Form 10-K that address activities, events or developments that Costilla
Energy, Inc. ("Costilla" or the "Company") expects, projects, believes or
anticipates will or may occur in the future, including such matters as oil and
gas reserves, future drilling and operations, future production of oil and gas,
future net cash flows, future capital expenditures and other such matters, are
forward-looking statements. These statements are based on certain assumptions
and analysis made by management of the Company in light of its experience and
its perception of historical trends, current conditions, expected future
developments and other factors it believes are appropriate in the
circumstances. Such statements are subject to a number of assumptions, risks
and uncertainties, including general economic and business conditions, prices
of oil and gas, the business opportunities (or lack thereof) that may be
presented to and pursued by the Company, changes in laws or regulations and
other factors, many of which are beyond the control of the Company.

ITEM 1.  BUSINESS.

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

GENERAL

         Costilla 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 South/East Texas
region, the Rocky Mountain region and the Permian Basin area of Texas and New
Mexico. In addition the Company owns 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 began operating in 1988 and conducted an initial public
offering of its common stock (the "IPO") in October 1996. As of January 1,
1998, the Company had total estimated net proved reserves of 15.0 Mmbbls of oil
and 148.6 Bcf of gas, aggregating 39.7 MMBOE, with a PV-10 Value of
approximately $196.7 million. The Company also has a substantial acreage
position consisting of 953,268 gross (713,107 net) acres at December 31, 1997,
665,734 gross (607,703 net) of which are undeveloped. The Company has
identified in excess of 600 drilling locations, of which 147 are included in
its proved reserves at January 1, 1998.

         The Company began active efforts to acquire and develop oil and gas
properties in 1993 and, from January 1, 1993 to December 31, 1997, closed eight
acquisitions for an aggregate purchase price of approximately $138 million. The
Company has not participated in the auction process, but rather has made
acquisitions through negotiated transactions.
The three most significant acquisitions have been:

 o   The acquisition of 6.0 MMBOE (as of July 1, 1997) of proved reserves,
     extensive undeveloped acreage and seismic data (the "Ballard Acquisition")
     from Ballard Petroleum LLC ("Ballard") in August 1997 for approximately
     $41.2 million, strengthening the Company's position in the Rocky Mountain
     Region.

 o   The acquisition of 10.6 MMBOE of proved reserves and undeveloped acreage
     located in the Permian Basin and South/East Texas regions in June 1996 for
     approximately $38.7 million (the "1996 Acquisition").

 o   The acquisition of 14.4 MMBOE of proved reserves and undeveloped acreage
     in the Permian Basin, South/East Texas and Rocky Mountain regions in June
     1995 for approximately $46.6 million (the "1995 Acquisition").




                                       3


<PAGE>   4

         Costilla has in-house exploration expertise which uses 3-D seismic
technology as a primary tool to identify drilling opportunities. Since the IPO,
the Company has made 13 new exploratory discoveries utilizing 3-D technology,
which have added proved reserves of 7.4 MMBOE at January 1, 1998. The Company
experienced an approximately 60% success rate in its 1997 exploratory drilling
activities, and an overall success rate of approximately 83% in its 1997
drilling activities.

         Through its acquisition, development and exploration activities, the
Company has grown substantially over the last four years, as measured by
reserves, production and cash flow.

 o   Estimated proved reserves have increased from 6.0 MMBOE at January 1, 1994
     to 39.7  MMBOE at  January 1, 1998, representing a compound annual growth 
     rate of 60%.

 o   PV-10 Values have increased from $26.4 million at January 1, 1994 to $196.7
     million at January 1, 1998, representing a compound annual growth rate of 
     65%.

 o   The Company has increased its average net daily production from 827 BOE
     for the year ended December 31, 1993 to 12,671 BOE for the year ended
     December 31, 1997, representing a compound annual growth rate of 98%.

 o   Adjusted EBITDA has increased from $1.8 million for the year ended
     December 31, 1993 to $40.0 million for the year ended December 31, 1997
     (pro forma for the Ballard Acquisition) which represents a compound annual
     growth rate of 117%.

 o   The Company's reserve growth has been achieved at an average all-in
     finding cost of $4.32 per BOE for the period from January 1, 1993 to
     January 1, 1998.

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

         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 by utilizing a three-pronged approach
which combines an active exploration program using 3-D seismic and other
technological advances with strategic property acquisitions and focused
development drilling. The Company's management and technical staff have
significant oil and natural gas experience in the areas of drilling and
completion, production operations, acquisitions and divestitures and reservoir
engineering. Most members of the Company's technical staff, having spent
substantial portions of their careers specializing in the Company's core
operating regions, have in-depth knowledge of these regions. The Company seeks
to reduce its operating and commodity risks by holding a geographically diverse
portfolio of properties, the reserves attributable to which were approximately
62% natural gas and 38% oil at January 1, 1998. The elements of the Company's
strategy may be further described as follows:

 o   Exploration Efforts. The Company has a staff of experienced geophysicists
     and geologists who perform extensive analysis of the Company's exploration
     prospects to carefully focus its 3-D seismic surveys and identify
     potential drilling locations. This focus allows the Company to 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 on known
     producing regions, where it can utilize the technical expertise and
     experience of its staff to identify exploration prospects which may have
     been previously overlooked.

 o   Strategic Property Acquisitions. The Company seeks to acquire producing
     properties where it has identified opportunities to increase production
     and reserves through both development and exploration activities. The
     Company has increased the value of the properties it has acquired by using
     its expertise and experience with current and advancing seismic, drilling
     and production technology to aggressively manage its operations of



                                       4
<PAGE>   5



     existing proved properties and successfully identify and develop
     previously unproved reserves on acquired acreage. The Company seeks to
     acquire reserves which 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.

 o   Development of Existing Properties.  The Company is actively pursuing 
     development of its existing properties.

 o   Control of Operations. The Company prefers to operate and own the
     majority working interest in its properties. This gives the Company
     greater control over future development, drilling, completion and lifting
     costs and the marketing of production. At January 1, 1998, the Company
     operated wells constituting approximately 76% of its total PV-10 Value.

RECENT DEVELOPMENTS

         The Company has had a number of recent significant developments with
respect to acquisitions, exploration successes and cost reduction efforts
through asset sales.

Acquisitions

         In keeping with its strategy to acquire properties with substantial
exploration potential, the Company consummated one significant acquisition in
1997 and an additional acquisition in January 1998. While both transactions
have proved reserves and current production, there are significant acreage
positions and exploration prospects included in each acquisition.

         Ballard Acquisition. In August 1997, the Company closed the Ballard
Acquisition for approximately $41.2 million. The oil and gas properties
acquired are located primarily in the Rocky Mountain region and had, as of July
1, 1997, approximately 6.0 MMBOE of proved reserves and 212,085 net undeveloped
acres. The Company also acquired the rights to 150 square miles of 3-D seismic
data and 42,000 miles of 2-D seismic data. The Company and Ballard have entered
into an Acquisition and Exploration Agreement that establishes an area of
mutual interest in the Rocky Mountain region in which the parties will jointly
own, acquire, explore and develop properties.

         Manti Acquisition. In January 1998 the Company closed a transaction
with Manti Resources, Inc. and acquired producing properties and associated
acreage located in south Texas (the "Manti Acquisition") in close proximity to
an exploration area the Company has been developing. The Manti Acquisition
included approximately 1.3 MMBOE of proved reserves at January 1, 1998,
approximately 30 square miles of 3-D seismic data and 16,202 gross and net
undeveloped acres. The purchase price was $10.5 million.

Exploration

         S.W. Speaks Field, Lavaca County, Texas. The Company has drilled its
initial exploratory well, the Migl-Mitchell #1, to a total depth of 14,950 feet.
The well is located within the Company's 46 square mile 3-D seismic survey and
it encountered two sand zones which totaled 190 feet of productive expanded
Wilcox sandstone. The well was completed from the lower of the two sands on
December 24, 1997. Testing of this well indicates an open flow potential of 116
Mmcf of gas per day. Gas sales commenced on January 20, 1998 and through March
24, 1998 this well has produced a total of 360 Mmcf of gas. As of March 15,
1998, completion operations are underway on the second well, which was drilled
to a total depth of 15,847 feet. This second well has penetrated three
productive Wilcox sand zones totaling 274 feet. The Company's working interest
in both of the initial wells is 100%. The Company owns 11,131 gross acres in
this field with a 57.7% average working interest. The Company is planning to
drill four wells in this field during 1998.

         Hopewell Project, Harrison and Panola Counties, Texas. The Company has
acquired 6,060 gross acres in a contiguous block on this project with a 100%
working interest. The project straddles two major producing structures in the
state line area of Texas and Louisiana. The Company's acreage position has
existing production from various formations and is underdeveloped in comparison
to offsetting leases. The Company has identified 100 drilling locations of
which 25 have been classified as containing proved undeveloped reserves at
January 1, 1998. The Company has drilled and completed the initial well at an
average rate of 19 Bbls of oil and 1,660 Mcf of gas per 


                                       5

<PAGE>   6

day from the Cotton Valley sand, and intends to dually complete the well in the
Travis Peak formation. The Company plans to drill eight wells on the Hopewell
project during 1998.

         Scott and Hopper Field, Brooks County, Texas. The Company has drilled
and completed the Scott and Hopper GU 1-5 well from the shallow Vicksburg
formation at an initial rate of approximately 2,000 Mcf of gas per day. The
well is located on the producing acreage acquired in the Manti Acquisition. The
Company owns a 3-D survey of the acreage and has identified 10 additional
drilling locations. The Company owns 15,882 gross acres on the field with an
average working interest of 100%. The Company has plans to drill at least five
wells in the Scott and Hopper field during 1998.

         Edwards/McElroy Ranch Prospect, Ector and Crane Counties, Texas. At
December 31, 1997, the Company had successfully completed a total of 26 wells
on the 80 square miles of 3-D seismic data. These wells have resulted in five
new discoveries in four formations. Costilla Energy has identified in excess of
50 drilling locations on the Company's 11,970 gross and net acres on this
prospect. The Company is planning to drill three wells in this project during
1998.


Divestitures

         The Company continuously evaluates its properties to identify
opportunities to divest properties which are marginally economic, have high
per-unit costs or have limited potential. From January 1, 1997 through December
31, 1997, the Company sold 6.6 MMBOE of what it considered high operating cost
reserves.

         Concho Sale. In December 1997, the Company consummated the sale of oil
and gas properties to Concho Resources, Inc. for $16.2 million (the "Concho
Sale"). These properties had assigned proved reserves of 4.9 MMBOE at December
31, 1997, consisted of approximately 1,600 gross wells, approximately 90% of
which were non-operated, included high operating cost properties and did not
fit the Company's overall business strategy.

         Gulf  Production  Sale.  In January 1998, the Company sold its interest
in approximately 190 gross wells in Oklahoma, approximately 75% of which were
non-operated, to Gulf Partners L.L.C. and Gulf Production Corp. for $2.5
million (the "Gulf Production Sale"). The properties had assigned proved
reserves of 0.7 MMBOE at January 1, 1998 and did not fit the Company's business
strategy.


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.


                                       6

<PAGE>   7



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, which affect the
marketing of gas produced by the Company, as well as the revenues received by
the Company for sales of such production. Since the mid-1980s, the FERC has
issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B
("Order 636"), that have significantly altered the marketing and transportation
of gas. Order 636 mandates a fundamental restructuring of 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. One of the FERC's
purposes in issuing the orders is to increase competition within all phases of
the gas industry. Order 636 and subsequent FERC orders on rehearing have been
appealed and are pending judicial review. It is difficult to predict the
ultimate impact of the orders on the Company and its gas marketing efforts.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of natural gas, and has
substantially increased competition and volatility in natural gas markets.
While significant regulatory uncertainty remains, Order 636 may ultimately
enhance the Company's ability to market and transport its gas, although it may
also subject the Company to greater competition and the more restrictive
pipeline imbalance tolerances and greater associated penalties for violation of
such tolerances.

         Sales of oil and natural gas liquids by the Company are not regulated
and are made at market prices. The price the Company receives from the sale of
these products is affected by the cost of transporting the products to market.
Effective as of January 1, 1995, the FERC implemented regulations establishing
an indexing system for transportation rates for oil pipelines, which,
generally, would index such rates to inflation, subject to certain conditions
and limitations. These regulations could increase the cost of transporting oil
and natural liquids by pipeline, although the most recent adjustment generally
decreased rates. The Company is not able to predict with certainty what effect,
if any, these regulations will have on it, but, other factors being equal, the
regulations may, over time, tend to increase transportation costs or reduce
wellhead prices for oil and natural gas liquids.


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 from the
Company's operations. Such laws and regulations may substantially increase the
cost of exploring for, developing or producing oil 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 



                                       7

<PAGE>   8

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
could have similar impact on the Company.

         The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), also known 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, 1997, the Company had 138 full time employees, the
majority of whom hold options under the Company's stock option plan. None of
the Company's employees is subject to a collective bargaining agreement. The
Company considers its relations with its employees to be good. In addition to
its employees, Costilla utilizes 10 consultants, and through its arrangements
with Ballard, has access to the approximately 30 employees of Ballard for oil
and gas activities within the Rocky Mountain region area of mutual interest.


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.



                                       8
<PAGE>   9


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 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>   10




ITEM 2.  PROPERTIES.

PRINCIPAL PROPERTIES

         The following table sets forth certain information, as of January 1,
1998, which relates to the principal oil and gas properties owned by the
Company.


<TABLE>
<CAPTION>


                                                                      PROVED RESERVES
                                                     --------------------------------------------------
                                                                                 TOTAL OIL   PERCENT OF
                                                      GROSS      OIL      GAS    EQUIVALENT  TOTAL OIL
                                                      WELLS    (MBbls)   (Mmcf)    (MBOE)    EQUIVALENT
                                                     -------   -------   ------- ----------  ----------
    REGION

<S>                                                      <C>     <C>      <C>       <C>            <C>  
South/East Texas .................................       559     2,034    87,699    16,651         41.9%
Rocky Mountain ...................................       625     6,390    26,975    10,886         27.4
Permian Basin ....................................       608     5,818    28,387    10,549         26.6
Other - Domestic .................................       247       315     4,258     1,024          2.6
Foreign - Moldova ................................        26       395     1,318       615          1.5
                                                     -------   -------   -------   -------   ----------

Total ............................................     2,065    14,952   148,637    39,725       100.00%
                                                     =======   =======   =======   =======   ==========

</TABLE>


         SOUTH/EAST TEXAS. At January 1, 1998, 41.9% of the Company's proved 
reserves were concentrated in the South/East Texas region, on shore.

         S.W. Speaks Field, Lavaca County, Texas. The Company has drilled its
initial exploratory well, the Migl-Mitchell #1, to a total depth of 14,950 feet.
The well is located within the Company's 46 square mile 3-D seismic survey and
it encountered two sand zones which totaled 190 feet of productive expanded
Wilcox sandstone. The well was completed from the lower of the two sands on
December 24, 1997. Testing of this well indicates an open flow potential of 116
Mmcf of gas per day. Gas sales commenced on January 20, 1998 and through March
24, 1998 this well has produced a total of 360 Mmcf of gas. As of March 15,
1998, completion operations are underway on the second well, which was drilled
to a total depth of 15,847 feet. This second well has penetrated three
productive Wilcox sand zones totaling 274 feet. The Company's working interest
in both of the initial wells is 100%. The Company owns 11,131 gross acres in
this field with a 57.7% average working interest. The Company is planning to
drill four wells in this field during 1998.

         Scott and Hopper Field, Brooks County, Texas. The Company has drilled
and completed the Scott and Hopper GU 1-5 well from the shallow Vicksburg
formation at an initial rate of approximately 2,000 Mcf of gas per day. The
well is located on the producing acreage acquired in the Manti Acquisition. The
Company owns a 3-D survey of the acreage and has identified 10 additional
drilling locations. The Company owns 15,882 gross acres on the field with an
average working interest of 100%. The Company has plans to drill at least five
wells in the Scott and Hopper field during 1998.

         Hopewell Project, Harrison and Panola Counties, Texas. The Company has
acquired 6,060 gross acres in a contiguous block on this project with a 100%
working interest. The project straddles two major producing structures in the
state line area of Texas and Louisiana. The Company's acreage position has
existing production from various formations and is underdeveloped in comparison
to offsetting leases. The Company has identified 100 drilling locations of
which 25 have been classified as containing proved undeveloped reserves at
January 1, 1998. The Company has drilled and completed the initial well at an
average rate of 19 Bbls of oil and 1,660 Mcf of gas per day from the Cotton
Valley sand, and intends to dually complete the well in the Travis Peak
formation. The Company plans to drill eight wells on the Hopewell project
during 1998.




                                      10
<PAGE>   11


         Sealy Field, Austin County, Texas. The Sealy field is a highly faulted
area which is further complicated by salt domes and is ideally suited to 3-D
seismic exploration. The Company has completed the acquisition and processing
of a 50 square mile 3-D survey and is currently engaged in interpretation of
the resulting data. The Company owns 19,048 gross acres in the Sealy field with
100% working interest. The Company expects to start drilling operations during
the fourth quarter of 1998.

         Cotton Valley, Limestone and Freestone Counties, Texas. The Company
owns a non-operated interest in the previously announced McMahon #4 well, a
Cotton Valley reef discovery which has been completed. Gas sales commenced on
March 6, 1998. As of March 13, 1998, the well was producing more than 9,000 Mcf
of gas per day. The Cotton Valley sandstone is encountered above the Cotton
Valley reef. The Company has gained significant experience in utilizing new
hydraulic fracturing techniques resulting in the completion of wells in the
Cotton Valley sandstone that might otherwise be considered non-commercial. The
Company owns 2,984 gross acres. The Company plans to drill two Cotton Valley
sandstone wells in 1998.

         ROCKY MOUNTAINS. At January 1, 1998, 27.4% of the Company's proved
reserves were concentrated in the Rocky Mountain region, which includes
Montana, North Dakota, Wyoming, Colorado and Utah. The Company significantly
increased both its reserves and undeveloped acres in the Rocky Mountain region
as a result of the Ballard Acquisition.

         O'Brien Springs Anticline Prospect, Carbon County, Wyoming. The
Company has acquired a 35 square mile 3-D seismic survey over the O'Brien
Springs Anticline. This 12 mile long structurally complex trend is expected to
yield several undrilled closures. The Company is encouraged by preliminary
interpretation of the data. Prospective horizons include the Tensleep, Nugget,
Dakota and Frontier sands at depths of up to 7,000 feet. The Company has 19,181
gross acres on this prospect and an approximate 30% working interest. The
Company plans to drill an initial test during 1998.

         Island Butte Field, Montezuma County, Colorado. The Company owns 4,196
gross acres in this field with a 57.5% average working interest. Recent
activity includes the conversion of non-producing wells to salt water disposal
systems and installation of submersible pumps on productive wells resulting in
increased production and a reduction in operating expenses. During 1998, the
Company is planning to drill two horizontal wells and two vertical wells in the
field.

         PERMIAN BASIN. At January 1, 1998, 26.6% of the Company's proved
reserves were concentrated in the Permian Basin, an approximately 70-county
region in West Texas and Southeast New Mexico.

         Edwards/McElroy Ranch Prospect, Ector and Crane Counties, Texas. At
December 31, 1997, the Company had successfully completed a total of 26 wells
on the 80 square miles of 3-D seismic data. These wells have resulted in five
new discoveries in four formations. Costilla Energy has identified in excess of
50 drilling locations on the Company's 11,970 gross and net acres on this
prospect. The Company is planning to drill three wells in this project during
1998.


MARKETING ARRANGEMENTS

         The Company sells the majority of its crude oil production based on
the posted price, plus market averages, in each area in which its crude oil is
produced. The majority of the Company's gas production is sold at spot market
prices. The term "spot market" is used herein to refer to contracts with terms
of six months or less or contracts which call for a redetermination of sales
prices every six months or earlier. The Company does not believe that the loss
of any of its principal oil or gas purchasers would have a material adverse
effect on it.



                                      11
<PAGE>   12
OIL AND GAS RESERVES

         The Company's estimated total proved reserves of oil and gas as of
January 1, 1998 were as follows:

<TABLE>
<CAPTION>
                                                                     JANUARY 1, 1998
                                                               ---------------------------
                                                                 OIL       GAS
                                                               (MBbls)    (Mmcf)    MBOE
                                                               -------   -------   -------

<S>                                                             <C>       <C>       <C>   
Proved developed producing ..................................   10,366    63,170    20,894
Proved developed non-producing ..............................      280    21,747     3,905
Proved undeveloped ..........................................    4,306    63,720    14,926
                                                               -------   -------   -------
   Total proved .............................................   14,952   148,637    39,725
                                                               =======   =======   =======
</TABLE>

         If the Manti Acquisition and the Gulf Production Sale (both of which 
were consummated in January 1998) were included in the January 1, 1998
estimates the total proved reserves would have been:

<TABLE>
<CAPTION>
                                                                          PRO FORMA
                                                                       JANUARY 1, 1998
                                                               ---------------------------
                                                                 OIL      GAS
                                                               (MBbls)   (Mmcf)     MBOE
                                                               -------   -------   -------
<S>                                                             <C>       <C>       <C>
Proved developed producing .................................    10,300    62,216    20,669
Proved developed non-producing .............................       312    24,018     4,315
Proved undeveloped .........................................     4,352    65,753    15,311
                                                               -------   -------   -------
   Total proved ............................................    14,964   151,987    40,295
                                                               =======   =======   =======
</TABLE>

         The future net cash flows from the Company's estimated proved reserves
as of January 1, 1998 were as follows:

<TABLE>
<CAPTION>
                                                                                                PRO FORMA
                                                                      JANUARY 1, 1998       JANUARY 1, 1998 (1)
                                                                      ------------------    -------------------
                                                                       (in thousands)
<S>                                                                   <C>                      <C>      
        Future net cash flows before income taxes . . . . . .         $ 305,387                $ 313,145
        Future net cash flows before income taxes,
           discounted at 10%  . . . . . . . . . . . . . . . .         $ 196,678                $ 202,452
</TABLE>

----------------------
(1) Includes adjustments for the Manti Acquisition and the Gulf Production
Sale.

         The domestic reserve estimates at January 1, 1998 were prepared by the
Company of which approximately 72% were reviewed by Williamson Petroleum
Consultants, Inc. Reserve estimates attributable to Moldova were prepared by W.
Scott Epley, P.E.

         There are numerous uncertainties in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data set forth in this Form 10-K are estimates only.
Although the Company believes such estimates to be reasonable, reserve
estimates are imprecise and should be expected to change as additional
information becomes available. Furthermore, estimates of oil and gas reserves,
of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be exactly measured, and
the accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment.
Accordingly, estimates of the economically recoverable quantities of oil and
gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future 


                                      12
<PAGE>   13

net cash flows expected therefrom prepared by different engineers or by the
same engineers at different times may vary substantially. Moreover, there can
be no assurance that the reserves set forth herein will ultimately be produced
or that the proved undeveloped reserves will be developed within the periods
anticipated. Variances from the estimates contained herein could be material.
In addition, the estimates of future net revenues from proved reserves of the
Company and the present value thereof are based upon certain assumptions about
production levels, prices and costs, which may not be correct. The Company
emphasizes with respect to such estimates that the discounted future net cash
flows should not be construed as representative of the fair market value of the
proved oil and gas properties belonging to the Company, because discounted
future net cash flows are based upon projected cash flows that do not provide
for changes in oil and gas prices or for escalation of expenses and capital
costs. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based. Actual results may
differ materially from the results estimated.

         While the Company's oil and gas reserves are attributable to
approximately 2,000 proved wells and locations, approximately 15% of the
Company's total proved reserves at January 1, 1998 were attributable to two
wells in the Southwest Speaks Field in Lavaca County, Texas. Both wells were
completed in the first quarter of 1998. Estimates of proved undeveloped
reserves, as well as estimates made early in the productive life of wells, may
be less reliable than reserve estimates attributable to wells which have longer
production histories. Any downward revision of the reserve estimates
attributable to the Southwest Speaks Field, or any interference in production
from such Field, could have a material adverse affect on the Company's future
cash flows and financial results.

         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.


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:






<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                                     ---------------------------
                                                       1997      1996      1995
                                                     -------   -------   -------
<S>                                                  <C>       <C>       <C>
Production:
   Oil (MBbls) ..................................      2,175     1,726       950
   Gas (Mmcf) ...................................     14,698     9,205     4,806
   MBOE .........................................      4,625     3,260     1,751

Average Sales Price:
   Oil (per Bbl) ................................    $ 17.77   $ 19.87   $ 15.53
   Gas (per Mcf) ................................       2.29      2.13      1.45

Costs Per BOE:
   Production costs, including severance taxes...    $  6.49   $  6.68   $  5.91
   Depreciation, depletion and amortization......       5.71      3.81      3.40
</TABLE>



                                      13
<PAGE>   14

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, 1997, the Company
was in the process of drilling seven gross (2.64 net) wells and was in the
process of completing one gross (one net) well as a producer which are not
reflected in the following table. The Company also drilled, or participated in
the drilling of 11 gross (3.89 net) service wells utilized as salt water
disposal or water injection wells which are not reflected in the following
table.


<TABLE>
<CAPTION>
                              1997                1996                1995
                       -----------------   -----------------   -----------------
                        GROSS      NET      GROSS      NET      GROSS      NET
                       -------   -------   -------   -------   -------   -------
<S>                    <C>       <C>       <C>       <C>       <C>       <C> 
Exploratory:
   Productive ......        15      8.38        13      8.88        10      4.58
   Dry .............        10      5.81         2      2.00         6      2.57
                       -------   -------   -------   -------   -------   -------
     Total .........        25     14.19        15     10.88        16      7.15
                       =======   =======   =======   =======   =======   =======

Development:
   Productive ......        86     58.72        16      9.93         1      0.44
   Dry .............        11      8.54         5      3.20        --        --
                       -------   -------   -------   -------   -------   -------
     Total .........        97     67.26        21     13.13         1      0.44
                       =======   =======   =======   =======   =======   =======

Total:
   Productive ......       101     67.11        29     18.81        11      5.02
   Dry .............        21     14.35         7      5.20         6      2.57
                       -------   -------   -------   -------   -------   -------
   Total ...........       122     81.46        36     24.01        17      7.59
                       =======   =======   =======   =======   =======   =======
</TABLE>


         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, 1997. Productive wells are
producing wells and wells capable of production.


<TABLE>
<CAPTION>
                                                                  ACTUAL (1)
                                                             -------------------
                                                              GROSS        NET
                                                             -------     -------
<S>                                                          <C>         <C>
Oil Wells ..............................................       1,348         677
Gas Wells ..............................................         623         205
                                                             -------     -------
    Total ..............................................       1,971         882
                                                             =======     =======
</TABLE>


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


                                       14

<PAGE>   15


ACREAGE

         The following table sets forth certain information regarding the
Company's developed and undeveloped leasehold acreage as of December 31, 1997.
Acreage in which the Company's interest is limited to royalty, overriding
royalty, mineral and similar interests is excluded.


<TABLE>
<CAPTION>
                           DEVELOPED          UNDEVELOPED            TOTAL
                       -----------------   -----------------   -----------------
  REGION                GROSS      NET      GROSS      NET      GROSS      NET
----------             -------   -------   -------   -------   -------   -------
<S>                    <C>       <C>       <C>       <C>       <C>       <C>
Permian Basin ......    74,012    35,626    80,535    62,377   154,547    98,003
South/East Texas ...   140,935    46,700    77,412    63,388   218,347   110,088
Rocky Mountain .....    56,491    20,503   484,373   458,629   540,864   479,132
Other ..............    16,096     2,575    23,414    23,309    39,510    25,884
                       -------   -------   -------   -------   -------   -------

Total ..............   287,534   105,404   665,734   607,703   953,268   713,107
                       =======   =======   =======   =======   =======   =======
</TABLE>


OTHER ACTIVITIES

         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 then affiliated
with the Company. The Company paid Redeco $90,000 and bore the first $2.0
million of concession expenses in return for a 50.0% interest in Redeco. The
Company and the other member of Redeco are each responsible for bearing 50.0% of
future expenses. The Concession Agreement covers the entire country
(representing approximately 8.0 million acres) with respect to oil and gas and
other minerals, and continues for various time periods depending on the nature
of the activity conducted. During 1997, Redeco drilled four successful gas wells
in southern Moldova which led to the first sales of Moldovan-produced natural
gas. Assuming satisfactory third party financing is arranged, thirty-five
additional wells are planned for 1998 following completion of a 15 mile pipeline
constructed by Redeco which will allow sales of produced gas into the Moldovan
gas distribution system. Redeco has also completed a 25 mile 2-D seismic survey.


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
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. The limits provided under its liability policies total $21.0
million. In addition, the Company maintains operator's extra expense coverage
which provides for care, custody and control of all material wells drilled by
the Company as operator. The Company


                                       15
<PAGE>   16

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 assurance can be given that the Company will be able to maintain adequate
insurance in the future at rates it considers reasonable.



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, 1997.


                                       16

<PAGE>   17



                                           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 under the trading symbol "COSE". The
following table sets forth the high and low closing price for the periods
presented:


<TABLE>
<CAPTION>
1996                                                            HIGH        LOW
                                                               ------     ------
<S>                                                            <C>        <C>   
     Fourth Quarter (October 3 inception of trading) .....     $13.63     $11.75

1997
     First Quarter .......................................     $15.50     $11.75
     Second Quarter ......................................     $14.50     $12.00
     Third Quarter .......................................     $14.25     $ 9.00
     Fourth Quarter ......................................     $16.00     $12.00
</TABLE>


         The Company had approximately 1,300 record and beneficial holders of
its Common Stock at December 31, 1997.

         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.


                                       17

<PAGE>   18



ITEM 6.  SELECTED FINANCIAL DATA.

         The following table sets forth selected financial data of Costilla
Energy, Inc. and its predecessors. 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 its
predecessors 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>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31,
                                                         --------------------------------------------------------------------------
                                                            1997            1996            1995            1994            1993
                                                         ----------      ----------      ----------      ----------      ----------
<S>                                                      <C>             <C>             <C>             <C>             <C>       
STATEMENT OF OPERATIONS DATA:
   Operating revenues ..............................     $   72,300      $   53,919      $   21,693      $    7,637      $    4,231
   Total revenues ..................................         76,501          55,026          21,816           7,836           4,397
   Expenses:
     Oil and gas production ........................         30,029          21,774          10,355           2,351           1,688
     General and administrative ....................          8,407           5,238           3,571           1,184             952
     Compensation related to option settlement .....             --              --             656              --              --
     Exploration and abandonments ..................          6,588           2,550           1,652             793             218
     Depreciation, depletion and amortization ......         26,409          12,430           5,958           1,847             884
     Impairment of oil and gas properties ..........         28,189              --              --              --              --
     Interest ......................................         12,979          11,281           4,591           1,458             605
                                                         ----------      ----------      ----------      ----------      ----------
   Income (loss) before income taxes and
     extraordinary item ............................        (36,100)          1,753          (4,967)            203              50
   Net income (loss) ...............................        (36,471)         (4,440)         (4,970)            163              73
STATEMENT OF CASH FLOWS DATA:
   Net cash provided by (used in):
     Operating activities ..........................     $   25,032      $   12,350      $    6,366      $    1,527      $      322
     Investing activities ..........................        (92,597)        (64,129)        (62,467)        (12,146)         (6,731)
     Financing activities ..........................         58,562          61,531          58,830          10,618           6,315
OTHER FINANCIAL DATA:
   Capital expenditures ............................     $  113,924      $   70,017      $   62,220      $   11,868      $    6,862
   Adjusted EBITDA (1) .............................         38,065          27,108           7,232           4,301           1,757
   Adjusted EBITDA/interest expense (1) ............            3.1x            2.6x            1.6x            2.9x            2.9x
BALANCE SHEET DATA (AS OF PERIOD END):
   Working capital (deficit) .......................     $  (11,511)     $   10,320      $    2,654      $    1,081      $    1,612
   Total assets ....................................        194,088         162,790          87,367          24,904          13,290
   Total debt, less current maturities .............        163,087         100,262          71,494          23,613          12,034
   Redeemable predecessor capital ..................             --              --          11,576              --              --
   Predecessor capital .............................             --              --          (7,445)           (747)             51
   Stockholders' Equity ............................            410          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, impairment of oil and gas properties,
     exploration and abandonment costs and extraordinary items. 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.


                                       18

<PAGE>   19



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. In June 1995, Costilla
consummated the 1995 Acquisition for a purchase price of approximately $46.6
million, in June 1996, Costilla consummated the 1996 Acquisition for a purchase
price of approximately $38.7 million and in August 1997, Costilla consummated
the Ballard Acquisition for a purchase price of approximately $41.2 million.

         The Company's strategy is to utilize its technical staff and
technological advances to increase its oil and gas reserves, production and cash
flow from operations through an active exploration program and the acquisition
and development 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 development of acquired properties.

         The Company has grown primarily through acquisitions which 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 development activities to
complement its acquisition efforts.

The Company has shown a significant increase in its oil and gas reserves and
production, especially due to its acquisitions from 1995 through 1997. The
following table sets forth certain operating data of Costilla for the periods
presented: 


<TABLE>
<CAPTION>
                                                   YEAR ENDED DECEMBER 31,
                                            ------------------------------------
                                               1997         1996         1995
                                            ----------   ----------   ----------
<S>                                         <C>          <C>          <C>
OIL AND GAS PRODUCTION:
   Oil (MBbls) ..........................        2,175        1,726          950
   Gas (Mmcf) ...........................       14,698        9,205        4,806
   MBOE .................................        4,625        3,260        1,751
AVERAGE SALES PRICES (1):
   Oil (per Bbl) ........................   $    17.77   $    19.87   $    15.53
   Gas (per Mcf) ........................         2.29         2.13         1.45
PRODUCTION COST (2):
   Per BOE ..............................   $     6.49   $     6.68   $     5.91
   Per dollar of sales ..................         0.42         0.40         0.48
DEPRECIATION, DEPLETION AND AMORTIZATION:
   Per BOE ..............................   $     5.71   $     3.81   $     3.40
   Per dollar of sales ..................         0.36         0.23         0.27
</TABLE>


----------
(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.


                                       19
<PAGE>   20


         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. If market prices of oil and gas exceed the strike price of
call options, the Company is obligated to pay the contracting counterparty an
amount equal to the contracted volumes times the difference between the market
price and the strike price, therefore, reducing the effective price received
for oil and gas sales by the amount paid to the counterparty. The net effect of
the Company's commodity hedging activities reduced oil and gas revenues by
$1,226,000, $1,705,000, and $80,000 for the years ended December 31, 1997, 1996
and 1995, respectively. The Company has purchased put options on 6,500 Bbls of
oil per day which establish a floor price of $18.50 per Bbl and sold call
options on 6,500 Bbls of oil per day at $22.55 per Bbl. These oil option
contracts continue through August 1998. The referenced oil prices are based
upon the price at which West Texas Intermediate crude oil ("WTI") trades on the
New York Mercantile Exchange ("NYMEX"). The Company has historically received a
gross wellhead sales price for oil of approximately 82 - 90% of the NYMEX
price. The Company has also purchased put options on 5,000 Mmbtu of gas per day
which provide for a floor of $2.00 per Mmbtu through October 1998.
Additionally, the Company has purchased put options on 40,000 Mmbtu of gas per
day which establish a floor price of $2.15 per Mmbtu and sold call options on
40,000 Mmbtu of gas per day at $2.55 per Mmbtu. These gas option contracts are
for the period April 1998 through October 1998. The referenced gas prices are
based upon the index price for Houston Ship Channel gas sales, which is
approximately 97% of NYMEX. The Company has historically received a gross
wellhead sales price for gas of approximately 87 - 90% of NYMEX.

       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 its then outstanding floating-rate indebtedness. The net
effect of the Company's interest rate hedging activities decreased interest
expense by approximately $25,000 for the year ended December 31, 1997. The net
effect of the Company's interest rate hedging activities increased interest
expense by approximately $442,000 for the year ended December 31, 1996.
Concurrent with the payment of all of the Company's floating rate debt from
proceeds of the initial public offering and the notes offering consummated 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 of $1,712,000 was recorded. A $60 million interest rate swap
expired in May 1997. As a result of the Company's borrowings against its line of
credit, which bears interest on a floating rate basis, the remaining $24 million
interest rate swap agreement again qualified as a hedge beginning in August
1997. At each borrowing date from October 1996 to August 1997, a portion of the
interest rate swap agreement was marked-to-market with the resulting gains or
losses recorded as investment income or loss while the hedge portion is being
amortized over the remaining life of the agreement. As a result of expiration
and marking the agreements to market, the Company recorded a net investment gain
of approximately $510,000 during the year ended December 31, 1997. Concurrent
with the payment of all of the Company's floating rate debt from proceeds of the
notes offering in January 1998, the interest rate swap agreement ceased to
qualify as a hedge. As a result of marking-to-market the interest rate swap
agreement in January 1998, the Company recorded an additional liability of
approximately $23,000.

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






                                      20


<PAGE>   21

RESULTS OF OPERATIONS


Year Ended December 31, 1997 Compared to Year Ended December 31, 1996

         The Company's total oil and gas revenues for the year ended December
31, 1997 were $72,300,000, representing an increase of $18,381,000 (34%) over
revenues of $53,919,000 in 1996. This increase was primarily due to successful
drilling activities and the 1996 Acquisition, which accounted for approximately
$11,099,000 and $9,214,000 of increased revenue, respectively. The Ballard
Acquisition accounted for approximately $3,372,000 of the increase. Gas
imbalances accounted for approximately $2,340,000 of the increase, with an
average price of $1.56 per Mcf. Approximately 50% of the gas imbalance relates
to production in prior periods against which a valuation allowance had been
recorded due to uncertainty of ultimate collection. During the year ended
December 31, 1997, uncertainties related to these imbalances were substantially
reduced and the related valuation allowance reversed. Management does not
expect similar effects from gas imbalances in future periods. These increases
were partially offset by the $2,152,000 net effect of lower commodity prices.
The average oil price per barrel received in 1997 was $17.77 compared to $19.87
in 1996, an 11% decrease, and the average gas price received in 1997 was $2.29
compared to $2.13 in 1996, a 7% increase. The sale of certain properties in
April 97 and December 31, 1996 also partially offset the increased revenues in
the amount of $3,607,000.

         Oil and gas production was 4,625 MBOE in 1997 compared to 3,260 MBOE
in 1996, a 42% increase. Of the 1,365 MBOE increase, approximately 657 MBOE was
due to successful drilling activities and 539 MBOE was due to the properties
acquired in the 1996 Acquisition. Gas imbalances accounted for approximately
249 MBOE of the increase. The Ballard Acquisition properties accounted for
approximately 219 MBOE of the increase. The sale of certain properties in April
1997 and December 1996 partially offset the increased production volumes.

           Interest and other revenues were $940,000 for the year ended
December 31, 1997 compared to $40,000 in 1996, representing an increase of
$900,000. Of this increase, $223,000 was related to increased interest income
due to increased funds earning interest. Gains on investment transactions of
$510,000 were recorded for the year ended December 31, 1997 related to an
interest rate swap contract which was marked-to-market. In the year ended
December 31, 1996 losses of $195,000 were recognized on certain investment
transactions. During 1997, losses of $146,000 related to an oil collar which
was marked-to-market. No comparable transactions existed in 1996.

         Other income was $3,261,000 for the year ended December 31, 1997
compared to $1,067,000 for 1996, representing an increase of $2,194,000 (206%).
Gains from the sale of certain oil and gas properties increased by
approximately $2,118,000. The remainder of the increase was due primarily to a
gain of approximately $70,000 recognized on the sale of the Company's interest
in a partnership which owned the Independence Plaza Building in Midland, Texas.

         Oil and gas production costs for the year ended December 31, 1997 were
$30,029,000 ($6.49 per BOE), compared to $21,774,000 in 1996 ($6.68 per BOE),
representing an increase of $8,255,000 (38%), with approximately $4,026,000 of
the increase relating to the 1996 Acquisition and $1,583,000 to successful
drilling activities. The remainder of the increase was due primarily to
increased treating and transportation costs due to increased gas production
and, to a lesser extent, the Ballard Acquisition, offset in part by the sale of
certain high operating cost properties in April 1997. On a per BOE basis,
production costs decreased $0.19 (3%) due to a combination of the sale of
certain high operating cost properties in April 1997, the gas imbalance volumes
and lower production costs on newly completed wells.

         General and administrative expenses for the year ended December 31,
1997 were $8,407,000, representing an increase of $3,169,000 (66%) from 1996 of
$5,238,000. The increase is primarily due to additional personnel and related
costs necessary to accommodate the acceleration of the Company's oil and gas
activities, the Ballard Acquisition, increased insurance costs and other costs
for a full twelve month period related to becoming a public company in October,
1996.

         Exploration and abandonment expense increased to $6,588,000 for the
year ended December 




                                      21
<PAGE>   22

31, 1997 compared to $2,550,000 in 1996. The Company incurred $2,117,000 of
seismic costs for the year ended December 31, 1997, compared to $913,000 in
1996. Dry hole and abandonment costs increased to $3,584,000 in 1997 from
$1,524,000 in 1996. The Company incurred $887,000 of other geological and
geophysical costs during the year ended December 31, 1997, compared to $113,000
in 1996. The increase in exploration and abandonments expense was primarily
related to the Company's increased drilling activities in 1997 compared to a
very low level of activity in 1996.

         D D & A expense for the year ended December 31, 1997 was $26,409,000
compared to $12,430,000 for 1996, representing an increase of $13,979,000
(112%). During the 1997 period, D D & A on oil and gas production was provided
at an average rate of $5.71 per BOE compared to $3.81 per BOE for 1996.
Approximately $3,751,000 of this increase was due to successful drilling
activities, $3,078,000 related to the 1996 Acquisition and an additional
$1,018,000 of the increase was due to the recording of gas imbalances. The
remainder of the increase was due primarily to the effect of lower oil and gas
prices at December 31, 1997 than those experienced at December 31, 1996.

         Impairment of oil and gas properties for the year ended December 31,
1997 was $28,189,000. No comparable expense was recorded in 1996. This
impairment expense was determined under the guidelines of FAS 121 (Impairment
of Long-Lived Assets) using estimates of net undiscounted cash flow and
estimated present values for the Company's oil and gas reserves based upon the
non-escalated prices used in the Company's December 31, 1997 reserve report.

         Interest expense was $12,979,000 for the year ended December 31, 1997,
compared to $11,281,000 for the comparable period in 1996. The $1,698,000 (15%)
increase was attributable primarily to increased levels of debt offset in part
by a decrease in the effective interest rate. The average amounts of applicable
interest-bearing debt in 1997 and 1996 were $128,207,000 and $95,671,000,
respectively. The effective annualized interest rate in 1997 was 10.1%, as
compared to 11.8% in 1996.

         Results of operations for the year ended December 31, 1997 include an
extraordinary charge of $219,000 compared to $4,975,000 for the comparable
period in 1996. These extraordinary charges related to the early extinguishment
of the Company's prior bank credit facilities and consisted of the unamortized
balance of previously capitalized debt issuance costs.


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 per Mcf received in 1996 was $2.13 compared
to $1.45 in 1995, a 47% increase.

         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, in each case including
enhancements of production after such 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 




                                      22
<PAGE>   23

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 received by 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 and
amortization of financing costs. 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 IPO and the sale of the
Existing Notes in October 1996.



LIQUIDITY AND CAPITAL RESOURCES


Net Cash Used in Operating Activities

         For the year ended December 31, 1997, net cash provided by operating
activities increased to $25.0 million from $12.4 million for the corresponding
period in 1996. Cash provided by operations, before changes in operating assets
and liabilities, increased to $16.6 million from $14.7 million for the
comparable period in 1996 due primarily to the Ballard Acquisition, 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,
1997 was $92.6 million. Approximately $41.2 million was used for the Ballard
Acquisition, $70.4 million was used for other oil and gas expenditures and $2.3
million was used for other property and equipment. During the year ended
December 31, 1997, approximately $21.3 million net cash was provided by sales
of oil and gas properties. For the year ended December 31, 1996, net cash used
in investing activities was $64.1 million. Approximately $38.7 million was used







                                      23

<PAGE>   24


for the 1996 Acquisition, $28.3 million for additional acquisition of producing
oil and gas properties and exploration and development activities and $3.0
million primarily for other property and equipment. During that period,
approximately $6.3 million net cash was provided by sales of oil and gas
properties.


Financing Activities

         For the year ended December 31, 1997, the Company incurred $87.3
million of debt, of which approximately $33.5 million was used to repay certain
prior bank debt, $41.2 million was used for the Ballard acquisition and the
remainder was used in connection with its exploration and development
activities. In addition, the Company used approximately $3.8 million for the
purchase of 330,500 shares of its common stock. 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 in October 1996. Approximately
$74.5 million was used for the extension and refinancing of prior debt, $38.7
million was used for the 1996 Acquisition and approximately $11.8 million was
used for general corporate purposes. In October 1996, this senior credit
facility was paid with the proceeds from the initial public offering and an
offering of senior notes, and the Company entered into a new $50.0 million
credit agreement. Approximately $19.9 million was outstanding under this senior
credit facility prior to its refinancing in August 1997.

         The Company replaced the above described senior credit facility with
the Revolving Credit Facility in August 1997. Approximately $19.9 million was
used for the extension and refinancing of the prior senior credit facility and
$11.2 million was used as a portion of the purchase price in the Ballard
Acquisition. The Revolving Credit Facility provides for a maximum availability
of $75.0 million, with an initial borrowing base of $50.0 million. Borrowings
under the Revolving Credit Facility bear interest, at the Company's option, at
a floating rate which is at or above the lender's prime rate or above the
applicable Eurodollar rate, depending on the percentage of committed funds
which have been borrowed. Interest is payable quarterly as to base rate loans,
and at the end of the applicable interest period as to Eurodollar rate loans.
The borrowing base of the Revolving Credit Facility is automatically reduced by
5% each quarter beginning in August 1999, and payments of principal are
required in each such quarter in which the outstanding principal balance is
greater than the reduced borrowing base. The remaining balance is payable on
August 31, 2002, the maturity date of the Revolving Credit Facility. In
connection with the sale of certain oil and gas properties on December 31, 1997
for proceeds of $16.2 million, the borrowing base was reduced to $36.5 million,
$33.0 of which was borrowed at December 31, 1997.

         Contemporaneous with entering into the Revolving Credit Facility, the
Company also entered into the Acquisition Credit Facility to provide the
remaining financing for the Ballard Acquisition. The Acquisition Credit
Facility was a term loan in the amount of $30.0 million which was repaid in
full in connection with the sale of notes by the Company described in the
following paragraph.

         In January 1998 the Company issued $80 million of 10 1/4% Senior Notes
due 2006 (the "Supplemental Notes Offering"). The net proceeds of the
Supplemental Notes Offering were approximately $78.8 million. The Company used
$30.0 million to repay the Acquisition Credit Facility and $32.5 million to
repay all but $0.5 million of the Revolving Credit Facility. In mid-January
1998 approximately $10.0 million of the remaining proceeds were used to fund
the Manti Acquisition.


Capital Resources

         Funding for the Company's business activities has historically been
provided by bank financings, cash flow from operations, equity sales, property
divestitures and joint ventures with industry participants. The 1995
Acquisition, 1996 Acquisition and Ballard Acquisition were substantially funded
by bank financings. The Company plans to execute its business strategy with
cash flow from operations, net proceeds from the Supplemental Notes Offering
and borrowings available under the Revolving 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.





                                      24
<PAGE>   25


         The Company believes that the increased availability under the
Revolving Credit Facility resulting from the application of net proceeds of the
Supplemental Notes Offering, the remaining net proceeds from the Supplemental
Notes Offering and cash flow from operations will be sufficient for its
budgeted 1998 capital expenditures. However, because the Company's ultimate
1998 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 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.

         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.

         Since December 31, 1997 oil and gas prices have continued to
deteriorate. The Company estimates that its cash flow would be reduced by $1.9
million and $2.1 million for each $1 per barrel reduction in the price of oil
and for each $0.10 per Mcf reduction in the price of gas, respectively.


Capital Expenditures

         The Company originally announced a 1998 capital budget of
approximately $70.0 million of which approximately $22.0 million was budgeted
for the acquisition of undeveloped acreage, seismic and exploitation
activities. Given the current low level of oil prices and its extensive
undeveloped acreage and seismic inventory, the Company has elected to
temporarily defer non-drilling activities pending an improvement in oil prices.
In addition, the Company intends to concentrate its drilling activities on gas
prospects. Since a significant portion of the Company's 1998 capital budget is
discretionary, the Company is able to increase or decrease its level of
activity as product prices warrant.


Recent Accounting Pronouncements

         INFORMATION SYSTEMS FOR THE YEAR 2000 - The Company will be required
to modify its information systems in order to accurately process data
referencing the year 2000. Because of the importance of occurrence dates in the
oil and gas industry, the consequences of not pursuing these modifications
could be very significant to the Company's ability to manage and report
operating activities. The Company's third-party software vendor for its
integrated oil and gas information system is currently modifying the system to
accurately handle the Year 2000 issue. All necessary programming modifications
are scheduled to be completed by December 31, 1998. From a cost viewpoint,
these modifications will be part of the routine updates the Company receives
from its third-party software vendor as part of its systems support contract
already in place. Thus, the Company believes it will not incur any marginal
costs with respect to the Year 2000 issue.

         REPORTING COMPREHENSIVE INCOME - In June 1997, the FASB issued
Statement of Accounting Standards No. 130 "Reporting Comprehensive Income"
("FAS 130") which establishes standards for reporting and display of
comprehensive income and its components in a full set of general-purpose
financial statements. Specifically, FAS 130 requires that an enterprise (i)
classify items of other comprehensive income by their nature in a financial
statement and (ii) display the accumulated balance of other comprehensive
income separately from retained earnings and additional paid-in capital in the
equity section of a statement of financial position. This statement is
effective for fiscal years beginning after December 15, 1997. The Company
anticipates that it will adopt the provisions of FAS 130 in its year ended
December 31, 1998 consolidated financial statements.

         Comprehensive income consists of the change in equity of a business
enterprise during a period from transactions and other events and circumstances
from nonowner sources. Specifically, this includes net income and other
comprehensive income, which is made up of certain changes in assets and
liabilities that are not reported in a statement of operations but are included
in the balances within a separate component of equity in a statement of
financial position. Such changes include, but are not limited to, unrealized
gains for marketable securities and future contracts, foreign currency
translation adjustments and minimum pension liability adjustments.





                                      25
<PAGE>   26


         SEGMENT REPORTING - In June 1997, the FASB issued Statement of
Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and
Related Information" ("FAS 131") which establishes standards for public
business enterprises for reporting information about operating segments in
annual financial statements and requires that such enterprises report selected
information about operating segments in interim financial reports issued to
shareholders. This statement also establishes standards for related disclosures
about products and services, geographic areas, and major customers. FAS 131 is
effective for financial statements for periods beginning after December 15,
1997.

         The Company operates in the one product line of oil and gas production
in limited geographic areas. This information and information about major
customers historically has been disclosed in the Company's annual financial
statements. The Company plans to implement SFAS 131 in its year ended December
31, 1998 financial statements.






                                      26
<PAGE>   27




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.





                                      27
<PAGE>   28




                                   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, 1997.

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, 1997.

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, 1997.

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, 1997.






                                   28

<PAGE>   29




                                    PART IV


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

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, although the Company did file an
amendment to Form 8-K dated November 12, 1997, amending its Form 8-K dated
September 12, 1997, which amendment included financial statements related to an
acquisition of oil and gas properties by the Company reported under Item 2 of
the original Form 8-K.

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 Exhibit 4.2)

             *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            First Supplemental Indenture dated January 16, 1998
                             by and between State Street Bank and Trust Company,
                             as Trustee, and the Company, as Issuer (including 
                             form of Global Certificate)

             #4.4            Form of Note

            **4.5            Form of Stock Certificate

            *10.1            Lease Agreement dated January 12, 1996 between 
                             Independence Plaza,Ltd. and Costilla Energy, L.L.C.

            *10.2            Concession Agreement dated July 6, 1995 between the
                             Government of the Republic of Moldova and Resource
                             Development Company Ltd., L.L.C. (DE)

            *10.3            Consolidation Agreement dated October 8, 1996

            *10.4            1996 Stock Option Plan

            *10.5            Employment Agreement between the Company and Bobby 
                             W. Page effective June 30, 1996

            *10.6            Employment Agreement between the Company and Cadell
                             S. Liedtke effective October 8, 1996



                                      29
<PAGE>   30

            EXHIBIT
            NUMBER           DESCRIPTION OF EXHIBIT

            *10.7            Employment Agreement between the Company and 
                             Michael J. Grella effective October 8, 1996

            *10.8            Employment Agreement between the Company and Henry 
                             G. Musselman effective October 8, 1996

            *10.9            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

           *10.10            Bonus Incentive Plan

           +10.11            First and Second Amendments to 1996 Stock Option
                             Plan of Costilla Energy, Inc.

           +10.12            First Amendment to Outside Directors Stock Option
                             Plan of Costilla Energy, Inc.

           +10.13            First, Second and Third Amendments to Bonus 
                             Incentive Plan of Costilla Energy, Inc.

          ++10.14            Purchase and Sale Agreement dated July 2, 1997 
                             between Ballard Petroleum LLC, as seller, and the
                             Company, as buyer

          ++10.15            Acquisition and Exploration Agreement effective as 
                             of July 1, 1997 by and between Ballard Petroleum,
                             LLC and the Company

           #10.16            Purchase Agreement dated January 13, 1998 among BT 
                             Alex. Brown Incorporated and Prudential Securities
                             Incorporated, as Initial Purchasers, and the
                             Company, as Issuer

           #10.17            Registration Rights Agreement dated January 16, 
                             1998 among BT Alex. Brown Incorporated and
                             Prudential Securities Incorporated, as Initial
                             Purchasers, and the Company, as Issuer

           #10.18            Amendment to Employment Agreement between the 
                             Company and Cadell S. Liedtke dated April 15, 1997

           #10.19            Amendment to Employment Agreement between the 
                             Company and Michael J. Grella dated April 15, 1997

           #10.20            Amendment to Employment Agreement between the 
                             Company and Henry G. Musselman dated April 15,
                             1997

           #10.21            Second Amendment to Employment Agreement between  
                             the Company and Henry G. Musselman dated April 15,
                             1997

           #10.22            Amendment to Employment Agreement between the
                             Company and Bobby W. Page dated April 15, 1997

           #10.23            Amended and Restated Credit Agreement dated as
                             of August 28, 1997 between Bankers Trust Company,
                             as Agent and Union Bank of California, N.A., as
                             Co-Agent and the Company


            
                                      30


<PAGE>   31

            EXHIBIT
            NUMBER           DESCRIPTION OF EXHIBIT

            #12.1            Computation of Ratio of Adjusted EBITDA to
                             Interest Expense

            #21.1            Subsidiaries of the Registrant

            #23.1            Consent of KPMG Peat Marwick LLP

            #23.2            Consent of Williamson Petroleum Consultants

            #23.3            Consent of W. Scott Epley, P.E.

            #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.

         +        Incorporated by reference to the Company's  Quarterly  Report
                  on Form 10-Q for the quarter ended June 30, 1997.

         ++       Incorporated by reference to the Company's Quarterly Report on
                  Form 10-Q for the quarter ended September 30, 1997.

         #        Filed herewith.


                                       31
<PAGE>   32




                              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, 1998                By:  */s/ MICHAEL J. GRELLA 
                                          --------------------------------------
                                          Michael J. Grella
                                          President, Chief Executive
                                          Officer and Director

         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, 1998                     */s/ CADELL S. LIEDTKE
                                          --------------------------------------
                                          Cadell S. Liedtke
                                          Chairman of the Board
                                          and Director

Date:  March 26, 1998                     */s/ MICHAEL J. GRELLA
                                          --------------------------------------
                                          Michael J. Grella
                                          President, Chief Executive Officer
                                          and Director

Date:  March 26, 1998                     */s/ HENRY G. MUSSELMAN
                                          --------------------------------------
                                          Henry G. Musselman
                                          Executive Vice President, Chief 
                                          Operating Officer and Director

Date:  March 26, 1998                     */s/ SAMUEL J. ATKINS, III
                                          --------------------------------------
                                          Samuel J. Atkins, III
                                          Director

Date:  March 26, 1998                     */s/ W. D. KENNEDY
                                          --------------------------------------
                                          W. D. Kennedy
                                          Director

Date:  March 26, 1998                     */s/ JERRY J. LANGDON
                                          --------------------------------------
                                          Jerry J. Langdon
                                          Director

Date:  March 26, 1998                     /s/ BOBBY W. PAGE
                                          --------------------------------------
                                          Bobby W. Page
                                          Senior Vice President and Chief 
                                          Financial Officer (principal
                                          accounting officer)

Date:  March 26, 1998                *By: /s/ BOBBY W. PAGE
                                          --------------------------------------
                                          Bobby W. Page
                                          Agent and Attorney in fact



                                       32
<PAGE>   33
                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<S>                                                                                                           <C>
Consolidated Financial Statements of Costilla Energy, Inc.:
       Independent Auditors' Report.......................................................................    F - 2
       Consolidated Balance Sheets as of December 31, 1997 and 1996.......................................    F - 3
       Consolidated Statements of Operations for the years ended December 31, 1997,
          1996 and 1995...................................................................................    F - 4
       Consolidated Statements of Stockholders' Equity for the years ended December 31, 1997,
          1996 and 1995...................................................................................    F - 5
       Consolidated Statements of Cash Flows for the years ended December 31, 1997,
          1996 and 1995...................................................................................    F - 6
       Notes to Consolidated Financial Statements.........................................................    F - 7
</TABLE>





                                      F-1
<PAGE>   34

                          INDEPENDENT AUDITORS' REPORT



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

We have audited the consolidated financial statements of Costilla Energy, Inc.
and subsidiaries as listed in the accompanying index. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1997, in conformity with generally accepted accounting
principles.



                                           KPMG PEAT MARWICK LLP

Midland, Texas
March 6, 1998



                                      F-2
<PAGE>   35

                              COSTILLA ENERGY, INC.

                           CONSOLIDATED BALANCE SHEETS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                    DECEMBER 31,   DECEMBER 31,
                                                                        1997           1996
                                                                     ---------      ---------
<S>                                                                  <C>            <C>      
                              ASSETS
CURRENT ASSETS:
   Cash and cash equivalents                                         $   3,615      $  12,618
   Accounts receivable:
       Trade, net                                                        5,241          6,675
       Affiliates                                                           --            332
       Oil and gas sales                                                 9,312          9,031
   Prepaid and other current assets                                        912          1,753
                                                                     ---------      ---------
           Total current assets                                         19,080         30,409
                                                                     ---------      ---------

PROPERTY, PLANT AND EQUIPMENT, AT COST:
   Oil and gas properties, using the successful efforts
     method of accounting:
       Proved properties                                               199,355        140,477
       Unproved properties                                              35,971          4,482
   Accumulated depletion, depreciation and amortization                (71,152)       (20,435)
                                                                     ---------      ---------
                                                                       164,174        124,524
   Other property and equipment, net                                     3,766          2,420
                                                                     ---------      ---------
           Total property, plant and equipment                         167,940        126,944
                                                                     ---------      ---------

OTHER ASSETS:
   Deferred charges                                                      4,212          4,503
   Note receivable - other                                                  --            250
   Other                                                                 2,856            684
                                                                     ---------      ---------
           Total other assets                                            7,068          5,437
                                                                     ---------      ---------
                                                                     $ 194,088      $ 162,790
                                                                     =========      =========

       LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
   Current maturities of long-term debt                              $      98      $      98
   Trade accounts payable                                               22,490         12,718
   Undistributed revenue                                                 4,566          3,517
   Other current liabilities                                             3,437          3,756
                                                                     ---------      ---------
           Total current liabilities                                    30,591         20,089
                                                                     ---------      ---------
LONG-TERM DEBT, LESS CURRENT MATURITIES                                163,087        100,262
                                                                     ---------      ---------
OTHER NONCURRENT LIABILITIES                                                --          1,870
                                                                     ---------      ---------

STOCKHOLDERS' EQUITY :
   Preferred stock, $.10 par value (3,000,000 shares authorized;
     no shares outstanding)                                                 --             --
   Common stock, $.10 par value (20,000,000 shares authorized;
     10,150,500 shares outstanding at December 31, 1997 and
     10,475,000 shares outstanding at December 31, 1996)                 1,015          1,047
   Additional paid-in capital                                           37,425         41,081
   Retained deficit                                                    (38,030)        (1,559)
                                                                     ---------      ---------
           Total stockholders' equity                                      410         40,569
                                                                     ---------      ---------
COMMITMENTS AND CONTINGENCIES                                               --             --
                                                                     ---------      ---------
                                                                     $ 194,088      $ 162,790
                                                                     =========      =========
</TABLE>


See accompanying notes to consolidated financial statements.

                                      F-3
<PAGE>   36

                              COSTILLA ENERGY, INC.

                      CONSOLIDATED STATEMENTS OF OPERATIONS
                      (IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
                                                                                    YEARS ENDED DECEMBER 31,
                                                                            ---------------------------------------
                                                                               1997           1996           1995
                                                                            ---------      ---------      ---------
<S>                                                                         <C>            <C>            <C>      
   REVENUES:
     Oil and gas sales                                                      $  72,300      $  53,919      $  21,693
     Interest and other                                                           940             40            123
     Gain on sale of assets                                                     3,261          1,067             --
                                                                            ---------      ---------      ---------
                                                                               76,501         55,026         21,816
                                                                            ---------      ---------      ---------

   EXPENSES:

     Oil and gas production                                                    30,029         21,325         10,024
     Oil and gas production - affiliates                                           --            449            331
     General and administrative                                                 8,407          4,682          2,910
     General and administrative - affiliates                                       --            556            661
     Compensation related to option settlement                                     --             --            656
     Exploration and abandonments                                               6,588          2,550          1,652
     Depreciation, depletion and amortization                                  26,409         12,430          5,958
     Impairment of oil and gas properties                                      28,189             --             --
     Interest                                                                  12,979         11,281          4,591
                                                                            ---------      ---------      ---------
                                                                              112,601         53,273         26,783
                                                                            ---------      ---------      ---------

       Income (loss) before federal income taxes and extraordinary item       (36,100)         1,753         (4,967)

   PROVISION FOR FEDERAL INCOME TAXES
     Current                                                                       62            176              3
     Deferred                                                                      90          1,042             --
                                                                            ---------      ---------      ---------
       Income (loss) before extraordinary item                                (36,252)           535         (4,970)

       Extraordinary loss resulting from early extinguishment of debt,
        net of deferred tax benefit of $129 and $1,042                           (219)        (4,975)            --
                                                                            ---------      ---------      ---------

   NET LOSS                                                                 $ (36,471)     $  (4,440)     $  (4,970)
                                                                            =========      =========      =========

   PREFERRED RETURN AND ACCRETION OF
     REDEEMABLE MEMBERS' CAPITAL                                            $      --      $  (3,930)     $  (2,842)
                                                                            =========      =========      =========

   LOSS BEFORE EXTRAORDINARY ITEM
     APPLICABLE TO COMMON EQUITY                                            $ (36,252)     $  (3,395)     $  (7,812)
                                                                            =========      =========      =========

   NET LOSS APPLICABLE TO COMMON EQUITY                                     $ (36,471)     $  (8,370)     $  (7,812)
                                                                            =========      =========      =========

   LOSS PER SHARE:
     Loss before extraordinary item                                         $   (3.49)     $   (0.52)     $   (1.50)

     Extraordinary loss resulting from early extinguishment of debt,
       net of deferred tax benefit                                              (0.02)         (0.77)            --
                                                                            ---------      ---------      ---------

     NET LOSS                                                               $   (3.51)     $   (1.29)     $   (1.50)
                                                                            =========      =========      =========

   WEIGHTED AVERAGE SHARES OUTSTANDING                                         10,383          6,473          5,200
                                                                            =========      =========      =========
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-4
<PAGE>   37

                              COSTILLA ENERGY, INC.

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

<TABLE>
<CAPTION>
                                                                                                          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, 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

    Net loss                                         --            --            --       (36,471)      (36,471)
    Common stock issued, net                         --             1            74            --            75
    Common stock repurchased and retired             --           (33)       (3,730)           --        (3,763)
                                               --------      --------      --------      --------      --------

BALANCE AT DECEMBER 31, 1997                   $     --      $  1,015      $ 37,425      $(38,030)     $    410
                                               ========      ========      ========      ========      ========
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-5
<PAGE>   38

                              COSTILLA ENERGY, INC.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                 YEARS ENDED DECEMBER 31,
                                                                        ---------------------------------------
                                                                           1997          1996           1995
                                                                        ---------      ---------      ---------
<S>                                                                     <C>            <C>            <C>       
CASH FLOWS FROM OPERATING ACTIVITIES:

   NET LOSS                                                             $ (36,471)     $  (4,440)     $  (4,970)

   ADJUSTMENTS TO RECONCILE NET LOSS TO NET CASH
      PROVIDED BY OPERATING ACTIVITIES:

     Depreciation, depletion and amortization                              26,409         12,430          5,958
     Impairment of oil and gas properties                                  28,189             --             --
     Exploration and abandonments                                           1,517            491             --
     Amortization of deferred charges                                         262          1,131            137
     Deferred income tax expense                                              (39)            --             --
     Allowance for doubtful accounts                                          208             --             --
     Other noncash                                                             --            103            (75)
     Compensation related to option settlement                                 --             --            656
     Gain on sale of oil and gas properties                                (3,261)        (1,067)            --
     Extraordinary loss resulting from early extinguishment of debt           348          6,017             --
     Gain on investment transactions                                         (534)            --             --
                                                                        ---------      ---------      ---------
                                                                           16,628         14,665          1,706

     Changes in operating assets and liabilities:
        Decrease (increase) in accounts receivable                          1,485         (8,462)        (4,818)
        Decrease (increase) in other assets                                (3,585)        (1,076)          (216)
        Increase (decrease) in accounts payable                            10,822          6,067          3,745
        Increase (decrease) in other liabilities                             (318)         4,475          2,655
        Increase (decrease) in deferred revenue                                --         (3,319)         3,294
                                                                        ---------      ---------      ---------
            Net cash provided by operating activities                      25,032         12,350          6,366
                                                                        ---------      ---------      ---------

CASH FLOWS FROM INVESTING ACTIVITIES:

   Additions to oil and gas properties                                   (111,580)       (67,010)       (61,500)
   Proceeds from sale of oil and gas properties                            21,327          6,388             --
   Additions to other property and equipment                               (2,344)        (3,007)          (720)
   Advances on notes receivable - other                                        --           (500)            --
   Advances on affiliate notes receivable                                      --             --           (247)
                                                                        ---------      ---------      ---------
            Net cash used in investing activities                         (92,597)       (64,129)       (62,467)
                                                                        ---------      ---------      ---------

CASH FLOWS FROM FINANCING ACTIVITIES:

   Borrowings under long-term debt                                         96,304        228,707         62,704
   Payments of long-term debt                                             (33,480)      (199,840)       (11,232)
   Proceeds from issuance of common stock, net                                 75         60,579             --
   Purchase of common stock                                                (3,763)            --             --
   Proceeds from redeemable predecessor capital                                --             --         10,000
   Deferred loan and financing costs                                         (574)        (8,191)        (2,587)
   Redemption of member's interest                                             --        (15,506)            --
   Distributions to members and withdrawals                                    --         (4,218)           (55)
                                                                        ---------      ---------      ---------
            Net cash provided by financing activities                      58,562         61,531         58,830
                                                                        ---------      ---------      ---------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                       (9,003)         9,752          2,729

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD                             12,618          2,866            137
                                                                        ---------      ---------      ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD                                $   3,615      $  12,618      $   2,866
                                                                        =========      =========      =========
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-6
<PAGE>   39

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)  ORGANIZATION AND NATURE OF OPERATIONS

     Costilla Energy, Inc. ("Costilla" or the "Company") 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, and
its wholly owned subsidiaries, to acquire the assets of CSL Management
Corporation ("CSL") (which owned 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.

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

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Principles of Consolidation

     As of December 31, 1997 and 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 owned 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.

     On January 1, 1997 CPC was merged into its parent and Costilla assumed the
business, assets and liabilities of CPC. On March 1, 1997 Valley was merged into
its parent and Costilla assumed the business, assets and liabilities of Valley.
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 properties were
transferred to Costilla on December 31, 1996.

     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.


                                      F-7
<PAGE>   40

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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, 1997, the Company had sales to two customers
each which exceeded 10% of total revenues, one for 14.5% and another for 12.2%.
During the year ended December 31, 1996, the Company had sales to one customer
which accounted for 11.2% 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 (loss) 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.

     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.

     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 amount received is
treated as a reduction of the cost of the interest retained.


                                      F-8
<PAGE>   41

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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 as determined based upon
discounted future net cash flows.

     Deferred Charges

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

     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. As of December 31, 1997, the Company had recorded a net gas
imbalance receivable for gas previously produced of approximately $2,341,000,
comprised of approximately 1,496,000 mcf at a net price of $1.56 per mcf.

     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.



                                      F-9
<PAGE>   42

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Earnings Per Share

     In February, 1997 the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128, "Earnings per Share" ("FAS 128")
which simplifies the existing standards for computing earnings per share ("EPS")
and makes them comparable to international standards. In accordance with the
provisions of FAS 128, the Company adopted FAS 128 in its year ended December
31, 1997 financial statements, although no restatement of prior period EPS
information has been necessary. Under FAS 128, primary EPS is replaced by
"basic" EPS, which excludes dilution and is computed by dividing income
available to common stockholders by the weighted average number of common shares
outstanding for the period. "Diluted" EPS, which is computed similarly to
fully-diluted EPS, reflects the potential dilution that could occur if
securities or other contracts to issue common stock were exercised or converted
into common stock or resulted in the issuance of common stock that then shared
in the earnings of the entity. For the years ended December 31, 1997, 1996 and
1995, the computation of diluted net loss per share was antidilutive; therefore,
the amounts reported for basic and diluted net loss per share were the same.
Basic and diluted net income (loss) per share is reduced by the preferred
return, accretion and redemption premium on redeemable members' capital for the
years ended December 31, 1996 and 1995. 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. Such
liabilities are generally recorded at their undiscounted amounts unless the
amount and timing of payments is fixed or reliably determinable.

     Reclassifications

     Certain reclassifications have been made to the 1995 financial statements
to conform to the 1996 and 1997 presentation.

(3)  ACQUISITION OF OIL AND GAS PROPERTIES

     On August 28, 1997, the Company consummated the purchase from Ballard
Petroleum LLC ("Ballard") of certain oil and gas properties for an adjusted
purchase price of approximately $41.2 million (the "Ballard Acquisition"). The
properties are located primarily in the Rocky Mountain region of the United
States. 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, August 28, 1997. In
addition, the Company and Ballard have entered into an Acquisition and
Exploration Agreement that establishes an area of mutual interest in the Rocky
Mountain region in which the parties will jointly own, acquire, explore and
develop 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 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 subsequently sold
for approximately $3.3 million its wholly-owned subsidiary, Costilla Pipeline
Corporation, which owned the Three 


                                      F-10
<PAGE>   43

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Rivers Pipeline 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 an adjusted purchase price of
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 1996 Acquisition , net of the related properties sold, and the Ballard
Acquisition had occurred on January 1, 1996. The pro forma amounts are not
necessarily indicative of the results that may be reported in the future.

<TABLE>
<CAPTION>
                                                                                  YEARS ENDED
                                                                                  DECEMBER 31,
                                                                              1997           1996
                                                                           ------------  ------------
                                                                                (IN THOUSANDS)
<S>                                                                          <C>           <C>     
Revenues ...............................................................     $ 82,189      $ 75,563
Net income (loss)  before extraordinary item ...........................      (39,029)        1,007
Net income (loss) per share before extraordinary item ..................        (3.76)         0.10
</TABLE>

(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, were required to adopt FAS 121 for fiscal years beginning after
December 15, 1995.

     In order to determine whether an impairment had occurred at December 31,
1997, 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. If the costs of a depletable unit did not
appear to be recoverable, impairment on the depletable unit was recorded equal
to the difference between the estimated present value and the costs. These
estimates of net undiscounted cash flow and estimated present values for the
Company's total oil and gas reserves were based upon the non-escalated prices
used in the Company's December 31, 1997 reserve report. Based on this process, a
noncash pre-tax writedown of $28,189,000 in the carrying amount of the Company's
proved properties was recorded at December 31, 1997. No writedown in the
carrying amount of the Company's proved properties was recorded at December 31,
1996.

(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 only deals
with reputable financial 



                                      F-11
<PAGE>   44

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

institutions as counterparties and anticipates 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.

     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. If market prices of oil and gas exceed the strike
price of call options, the Company is obligated to pay the contracting
counterparty an amount equal to the contracted volumes times the difference
between the market price and the strike price, therefore, reducing the effective
price received for oil and gas sales by the amount paid to the counterparty.

     The net effect of the Company's commodity hedging activities reduced oil
and gas revenues by $1,226,000, $1,705,000, and $80,000 for the years ended
December 31, 1997, 1996 and 1995, respectively.

     The following table sets forth the future volumes hedged by year and the
weighted-average strike price of the option contracts at December 31, 1997:

<TABLE>
<CAPTION>
                                                  OIL            GAS
                                              DAILY VOLUME   DAILY VOLUME                                   STRIKE PRICE
                                                (BBLS)          (MMBTU)               TERM                  PER BBL/MMBTU
                                              ------------   ------------          ------------             -------------
<S>                                              <C>         <C>               <C>                     <C>
   Oil:
        1998 ...............................     6,500              --            Jan 98 - Aug 98         $18.50 - $22.55(a)
   Gas:
        1998 ...............................        --           5,000            Jan 98 - Oct 98             $2.00 (b)
</TABLE>

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

     (a)  Represents the strike prices 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.

     In March 1998 the Company purchased put options on 40,000 Mmbtu of gas per
day, establishing a floor price of $2.15 per Mmbtu, and sold call options on
40,000 Mmbtu of gas per day, establishing a ceiling price at $2.55 per Mmbtu,
for the period April 1998 through October 1998.

     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. A $60 million interest rate swap agreement expired in May 1997. As a
result of the Company's borrowings against its line of credit, which bears
interest on a floating rate basis, the remaining $24 million interest rate swap
agreement again fully qualified as a hedge in August 1997. At each borrowing
date from October 1996 to August 1997, a portion of the interest rate swap
agreement was marked-to-market with the resulting gains or losses recorded as
investment income or loss while the hedge portion was being amortized over the
remaining life of the agreement. As a result of expiration and marking the
agreements to market, the Company recorded a net investment gain of
approximately $510,000 during the year ended December 31, 1997. Concurrent with
the payment of all of the Company's floating rate debt from proceeds of the 1998
Notes (as defined and discussed in Note 7), the interest rate swap agreement
ceased to qualify as a hedge. As a result of marking-to-market the interest rate
swap agreement at that time, the Company recorded an additional liability of
approximately $23,000. The interest rate swap agreement in place as of December
31, 1997 has a notional amount of $24 million with a fixed rate of 7.5% and will
expire in January, 1999.

                                      F-12
<PAGE>   45

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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, 1997 and 1996. 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.

<TABLE>
<CAPTION>
                                                                      1997                       1996
                                                           ------------------------      --------------------
                                                             CARRYING       FAIR         CARRYING      FAIR
                                                             AMOUNT         VALUE         AMOUNT       VALUE
                                                           -----------    ---------      ----------   -------
Financial Assets:                                                           (IN THOUSANDS)
<S>                                                        <C>           <C>           <C>           <C>      
    Cash, cash equivalents and restricted cash .......     $   3,615     $   3,615     $  12,618     $  12,618
    Receivables (trade) ..............................         5,241         5,241         6,675         6,675
    Receivables (oil and gas sales) ..................         9,312         9,312         9,031         9,031
    Commodity option contracts .......................           190         1,488           592        (2,172)
    Gas imbalances receivable ........................         2,341         3,087            --            --
    Notes receivable - affiliate .....................           476           476           684           542
    Notes receivable - other .........................           250           250           500           500

Financial liabilities:
    Payables (trade) .................................        22,490        22,490        12,718        12,718
    Long-term debt ...................................       163,087       167,587       100,262       105,512
    Interest rate swap and option agreements .........           521           493         1,712         1,712
</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.

     Gas imbalances receivable: The carrying amount reflects the net quantity of
gas imbalances receivable based upon current prices at December 31, 1997.

     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.

     Long-term debt: The fair value of the Company's long-term debt is based
upon the quoted market price for the senior notes at December 31, 1997 and 1996
and the carrying amounts outstanding under the two credit facilities at December
31, 1997 (see Note 7 for a complete discussion of long-term debt).

     Interest rate swap agreements: At December 31, 1997, the Company had an
interest rate swap agreement outstanding with a notional amount of $24 million.
This agreement is more fully described in Note 5. The carrying amount is equal
to the sum of the unamortized premiums paid for the agreement and the fair
value. The fair values 


                                      F-13
<PAGE>   46

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of each of the open interest rate swap agreements was obtained from bank quotes
and represent the estimated amount the Company would pay upon termination of the
agreements at December 31, 1997 and 1996, taking into consideration interest
rates at that date.

(7)  LONG-TERM DEBT

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

<TABLE>
<CAPTION>
                                                                      DECEMBER 31,
                                                                 ---------------------
                                                                   1997         1996
                                                                 --------     --------
<S>                                                              <C>          <C>     
      10.25% Senior Notes due 2006 .........................     $100,000     $100,000
      Revolving Credit Facility ............................       33,000          100
      Acquisition Credit Facility ..........................       30,000           --
      Other notes payable ..................................          185          260
                                                                 --------     --------
                                                                  163,185      100,360
                   Less current maturities .................           98           98
                                                                 --------     --------
                                                                 $163,087     $100,262
                                                                 ========     ========
</TABLE>

     In August 1997, the Company entered into a credit agreement (the "Revolving
Credit Facility") with Bankers Trust Company, as agent, to refinance its
existing bank indebtedness and to finance a portion of the Ballard Acquisition
purchase price. The Revolving Credit Facility provides for a maximum
availability of $75.0 million, $33.0 million of which was borrowed at December
31, 1997 against an available borrowing base of $36.5 million at such date.
Borrowings under the Revolving Credit Facility bear interest, at the Company's
option, at a floating rate which is at or above the Lender's prime rate or above
the applicable Eurodollar rate, depending on the percentage of committed funds
which have been borrowed. Interest is payable quarterly as to base rate loans,
and at the end of the applicable interest period as to Eurodollar loans. The
borrowing base of the Revolving Credit Facility is automatically reduced by 5%
each quarter beginning in August 1999, and payments of principal are required in
each quarter in which the outstanding principal balance is greater than the
reduced borrowing base. The remaining balance is payable on August 28, 2002, the
maturity date of the Revolving Credit Facility. Under the Revolving Credit
Facility, the Company is obligated to pay certain fees to the lender, including
a commitment fee based on the unused portion of the commitment. The Revolving
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 (i) a current ratio of not less than 1.0 to
1.0, including amounts available under the Revolving Credit Facility and
excluding current maturities under the Revolving Credit Facility and the
Acquisition Credit Facility, (ii) a ratio of EBITDA to interest expense of not
less than 2.50 to 1 and (iii) a minimum tangible net worth. Borrowings under the
Revolving Credit Facility are secured by substantially all of the assets of the
Company.

     In August 1997, the Company also entered into a second credit agreement
(the "Acquisition Credit Facility") with Bankers Trust Company, as agent, to
provide funds for a substantial portion of the Ballard Acquisition purchase
price. The Acquisition Credit Facility is a term loan in the amount of $30.0
million and is subject to a borrowing base to be determined at least
semi-annually. Borrowings under the Acquisition Credit Facility bear interest,
at the Company's option, at a floating rate which is above the Lender's prime
rate or the applicable Eurodollar rate. Interest is payable quarterly as to base
rate loans, and at the end of the applicable interest period as to Eurodollar
loans. Principal payments commence in February 1998, and are $1.7 million
quarterly for the first year and $1.4 million each quarter thereafter for two
years, with all remaining amounts due at maturity, February 28, 2001. Borrowings
under the Acquisition Credit Facility are secured by the assets acquired in the
Ballard Acquisition.



                                      F-14
<PAGE>   47

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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 1996 Credit Facility
provided for 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 provided a maximum availability of $50.0
million (which amount was also the initial borrowing base), $100,000 of which
was outstanding at December 31, 1996. Availability under the borrowing base was
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 lender. Borrowings under the 1996 Credit Facility bore interest, at the
Company's option, at a floating rate which was at or above the NationsBank, N.A.
prime rate or the LIBOR rate, depending on the percentage of committed funds
which were borrowed. Interest was payable quarterly and principal was to be
amortized in twelve equal installments commencing two years from the date of the
credit agreement. Under the 1996 Credit Facility, the Company was obligated to
pay certain fees to the lender, including a commitment fee which ranged from
0.30% to 0.40% based on the unused portion of the commitment. The 1996 Credit
Facility contained customary restrictive covenants (including restrictions on
the payment of dividends and the incurrence of additional indebtedness) and
required 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 were
secured by substantially all of the assets of the Company and any subsidiary of
the Company that guaranteed the Company's obligations under the 1996 Credit
Facility. None of the Company's subsidiaries 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
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.

     In January 1998, the Company issued an additional $80 million aggregate
principal amount of 10.25% Senior Notes due October 1, 2006 (the " 1998 Notes").
The notes were sold at a premium (102.5%) and interest is payable April 1 and
October 1, commencing April 1, 1998. The 1998 Notes may not be redeemed prior to
October 1, 2001, and thereafter at a premium reducing to par, plus interest, by
maturity. The 1998 Notes are subject to the same terms and conditions as the
Notes. Net proceeds from the sale of the 1998 Notes of approximately $78.8


                                      F-15
<PAGE>   48

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million were used to repay the Acquisition Credit Facility in full, all but
$500,000 of the Revolving Credit Facility and the remainder was used for general
corporate working capital needs.

     In light of the issuance of the 1998 Notes and the concurrent repayment of
the Acquisition Credit Facility , there are no current maturities of long-term
debt. Therefore, all amounts owed under the Revolving Credit Facility and
Acquisition Facility as of December 31, 1997 have been classified as long-term
obligations.

     The Company paid interest on long-term debt of $12,198,937, $8,838,971 and
$4,453,684 in 1997, 1996 and 1995, respectively.

(8)  INCOME TAXES

     Concurrent with the Offerings, 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) and amounts separately allocated were as
follows (thousands):

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                                        --------------------
                                                         1997         1996
                                                        -------      -------
<S>                                                     <C>          <C>    
            Income (loss) before extraordinary item     $   152      $ 1,218

            Extraordinary loss resulting from early
               extinguishment of debt                      (129)      (1,042)
                                                        -------      -------

                                                        $    23      $   176
                                                        =======      =======
</TABLE>

     In 1997, the Company's effective tax rate differs from the U.S. Federal
statutory rate primarily because of a valuation allowance established for net
operating loss carryforwards, as discussed below. The Company's effective tax
rate does not differ materially from the U.S. Federal statutory rate in 1996.

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

<TABLE>
<CAPTION>
                                                                           DECEMBER 31,
                                                                      ----------------------
                                                                        1997          1996
                                                                      --------      --------
<S>                                                                   <C>           <C>     
         Deferred tax assets (liabilities):
            Net operating loss carryforwards                          $ 15,331      $  2,805
            Interest rate swap agreements                                  116           599
            Oil and gas properties, principally due
               to differences in depletion, impairment
               and the deduction of intangible drilling
               costs for tax purposes                                    1,253        (1,692)
            Other                                                        1,365            --
                                                                      --------      --------

         Net deferred tax asset                                         18,065         1,712
         Valuation allowance of net deferred tax asset                 (18,065)       (1,712)
                                                                      --------      --------
         Net deferred tax asset, net of valuation allowance           $     --      $     --
                                                                      ========      ========
</TABLE>


                                      F-16
<PAGE>   49

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     A valuation allowance 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, 1997, the Company had net operating loss carryforwards of
approximately $43.8 million, which are available to offset future regular
taxable income, if any. The carryforwards expire December 31, 2011 and 2012.

(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, 1997, 1996 and 1995 was
$376,978, $416,442 and $311,221, respectively. Future minimum lease commitments
under noncancellable operating leases at December 31, 1997 are as follows
(thousands):

<TABLE>
<S>                                                                <C>
                 1998..........................................    $    394,372   
                 1999..........................................         376,699   
                 2000..........................................         327,517   
                 2001..........................................         352,302   
                 2002..........................................         343,924   
             Thereafter........................................       1,023,048   
</TABLE>

     Employment Agreements

     In 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 $1,035,000 for 1998.

     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 



                                      F-17
<PAGE>   50

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

material fixed financial commitments with respect to the Concession. As of
December 31, 1997, the Company's share of costs expended was $3,681,137.

     Letters of Credit

     As a result of certain bonding and hedging counterparty requirements, the
Company has caused irrevocable letters of credit to be issued by a bank totaling
$996,000. As of December 31, 1997, 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
$122,336, $58,713, and $22,531 in 1997, 1996 and 1995, 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-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:

<TABLE>
<S>                                                                   <C>        
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
                                                                      ===========
</TABLE>



                                      F-18
<PAGE>   51

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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.

     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, up to an aggregate of
$5,500,000. 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.

     The plan was amended during 1997 to provide that a total of 100,000 shares
be authorized and reserved for issuance under this plan and that each person
qualifying as an outside director shall receive an option for 5,000 shares each
year that such person is elected as a director of the Company. During the year
ended December 31, 1997, options on 15,000 shares were granted under this plan,
leaving 85,000 options available for future grant under the plan as of December
31, 1997. The options granted during 1997 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 grant. The weighted average fair value, as calculated under the
provisions of FAS 123, of the options granted in 1997 was $8.56 per share.

     Bonus Incentive Plan

     The Bonus Incentive 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 


                                      F-19
<PAGE>   52

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

     The plan was amended during 1997 to provide that the plan be administered
by the Compensation Committee of the Board of Directors, that awards of
incentive compensation under this plan be made within 120 days after the
expiration of each fiscal year and the removal of the exclusion of ten percent
or more shareholders as eligible participants in the plan. During the year ended
December 31, 1997, 4,500 shares were issued under this plan at the current
market price of $13.38 per share.

     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 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 135 employees
who are eligible to participate in the plan.

     The plan was amended during 1997 to provide that the plan be administered
by the Compensation Committee of the Board of Directors and that a total of
1,250,000 shares be authorized and reserved for issuance under this plan.

     No options were issued under this plan during 1997. During 1996, the
Company granted 711,750 stock options pursuant to the 1996 Stock Option Plan,of
which 1,500 shares were exercised in 1997. There were 547,750 options available
for future grant under the plan as of December 31, 1997. The options granted
during 1996 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 weighted
average 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, 1997 and 1996 would
have been adjusted to the following pro forma amounts: 


                                      F-20
<PAGE>   53

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                            1997               1996
                                                       -------------      -------------
<S>                                                    <C>                <C>           
            Net loss                                   $ (37,740,000)     $  (6,285,276)

            Net loss per share                                 (3.63)             (1.58)
</TABLE>

     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 1997 and 1996:

<TABLE>
<CAPTION>
                                                      1997                  1996
                                                   ----------          -------------
<S>                                                    <C>                 <C>  
          Risk-free interest rate                      6.25%               6.25%
          Expected life                              5 years             5 years
          Expected volatility                            80%                 54%
          Expected dividend yield                         0%                  0%
</TABLE>

(13) RELATED PARTY TRANSACTIONS

     Certain members and officers of the Company have owned interests in and
held 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. 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, including accrued interest and is dated May
22, 1996. The note is unsecured and is payable upon demand. During 1997, the
Company created an allowance of $208,000 related to these notes to reflect the
estimated present value of anticipated future payments on these notes. During
1997, 1996 and 1995, the Company paid $561,343, $520,519 and $612,139,
respectively, to A&P for goods and services provided.

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

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

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

     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.



                                      F-21
<PAGE>   54

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(14) OIL AND GAS EXPENDITURES

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

<TABLE>
<CAPTION>
                                                           YEARS ENDED DECEMBER 31,
                                             ---------------------------------------------------
                                                 1997                1996                1995
                                             -----------         -----------         -----------
                                                                 (THOUSANDS)
<S>                                          <C>                 <C>                 <C>        
Property acquisition costs:
     Proved                                  $    25,731         $    39,505         $    52,470
     Unproved                                     32,415                 721               1,742
Exploration                                       16,194               6,760               5,627
Development                                       43,942              17,723                 158
                                             -----------         -----------         -----------
                                             $   118,282         $    64,709         $    59,997
                                             ===========         ===========         ===========
</TABLE>

(15) 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, 1997 and
1995 and by Williamson Petroleum Consultants as of December 31, 1996. Williamson
Petroleum Consultants performed a review of approximately 72% of the Company's
estimated United States reserves as of December 31, 1997 (on a PV-10 basis). The
Moldova reserve estimates were prepared by W. Scott Epley, P.E. as of December
31, 1997. 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
United States reserve estimates utilizing an oil price of $15.29 per Bbl and a
gas price of $2.20 per Mcf as of December 31, 1997 and an oil price of $24.17
per Bbl and a gas price of $3.96 per Mcf as of December 31, 1996. The Company
has presented the Moldovan reserve estimates utilizing an oil price of $16.00
per Bbl and a gas price of $2.08 per Mcf as of December 31, 1997.

     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-22
<PAGE>   55

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                      UNITED STATES                    MOLDOVA                      TOTAL
                                            -------------------------------     ---------------------     -----------------------
                                             OIL AND               NATURAL       OIL AND     NATURAL       OIL AND        NATURAL
                                            CONDENSATE              GAS         CONDENSATE     GAS        CONDENSATE        GAS
                                             (MBbls)               (MMcf)        (MBbls)      (MMcf)        (MBbls)        (MMcf)
                                             --------             --------      --------     --------      --------      --------
<S>                                             <C>                 <C>                                       <C>          <C>   
Total Proved Reserves:
Balance, January 1, 1995 ...............        4,009               27,512            --           --         4,009        27,512
     Revisions of previous estimates ...         (570)                 425            --           --          (570)          425
     Extensions and discoveries ........          605                8,922            --           --           605         8,922
     Production ........................         (950)              (4,806)           --           --          (950)       (4,806)
     Purchases of minerals-in-place ....        7,694               46,099            --           --         7,694        46,099
                                             --------             --------      --------     --------      --------      --------

Balance, December 31, 1995 .............       10,788               78,152            --           --        10,788        78,152
     Revisions of previous estimates ...        1,782                5,440            --           --         1,782         5,440
     Extensions and discoveries ........        1,169               13,581            --           --         1,169        13,581
     Production ........................       (1,726)              (9,205)           --            --       (1,726)       (9,205)
     Sales of minerals-in-place ........         (119)                (482)           --           --          (119)         (482)
     Purchases of minerals-in-place ....        5,106               32,786            --           --         5,106        32,786
                                             --------             --------      --------     --------      --------      --------

Balance, December 31, 1996 .............       17,000              120,272            --           --        17,000       120,272
     Revisions of previous estimates ...       (3,651)               3,064            --           --        (3,651)        3,064
     Extensions and discoveries ........        2,465               58,888           395        1,318         2,860        60,206
     Production ........................       (2,175)             (14,698)           --           --        (2,175)      (14,698)
     Sales of minerals-in-place ........       (2,065)             (27,743)           --           --        (2,065)      (27,743)
     Purchases of minerals-in-place ....        2,983                7,536            --           --         2,983         7,536
                                             --------             --------      --------     --------      --------      --------

Balance, December 31, 1997 .............       14,557              147,319           395        1,318        14,952       148,637
                                             ========             ========      ========     ========      ========      ========

Proved Developed Reserves:
     December 31, 1994 .................        2,632               16,340            --           --         2,632        16,340
     December 31, 1995 .................        8,566               57,393            --           --         8,566        57,393
     December 31, 1996 .................       14,018               90,023            --           --        14,018        90,023
     December 31, 1997 .................       10,646               84,558            --          359        10,646        84,917
</TABLE>


                                      F-23
<PAGE>   56

                              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 shown 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>
<CAPTION>
                                                                                        YEARS ENDED DECEMBER 31,
                                                                                ---------------------------------------
                                                                                  1997            1996           1995
                                                                                ---------      ---------      ---------
                                                                                              (THOUSANDS)
<S>                                                                             <C>            <C>            <C>      
                      UNITED STATES
Future cash flows .........................................................     $ 547,584      $ 887,100      $ 350,653
Future costs:
     Production ...........................................................      (205,454)      (323,288)      (145,510)
     Development ..........................................................       (41,291)       (25,469)       (16,806)
                                                                                ---------      ---------      ---------

Future net cash flows before income taxes .................................       300,839        538,343        188,337
Future income taxes .......................................................        31,249        144,836             --
                                                                                ---------      ---------      ---------
Future net cash flows .....................................................       269,590        393,507        188,337
10% annual discount for estimated timing of
     cash flows ...........................................................       (95,704)      (165,273)       (75,041)
                                                                                ---------      ---------      ---------

Standardized measure of discounted net cash flows .........................     $ 173,886      $ 228,234      $ 113,296
                                                                                =========      =========      =========


                         MOLDOVA
Future cash flows .........................................................     $   9,063      $      --      $      --
Future costs:
     Production ...........................................................        (1,943)            --             --
     Development ..........................................................        (2,572)            --             --
                                                                                ---------      ---------      ---------

Future net cash flows before income taxes .................................         4,548             --             --
Future income taxes .......................................................           951             --             --
                                                                                ---------      ---------      ---------
Future net cash flows .....................................................         3,597             --             --
10% annual discount for estimated timing of
     cash flows ...........................................................        (1,560)            --             --
                                                                                ---------      ---------      ---------

Standardized measure of discounted net cash flows .........................     $   2,037      $      --      $      --
                                                                                =========      =========      =========
</TABLE>


                                      F-24
<PAGE>   57

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                      YEARS ENDED DECEMBER 31,
                                                                                ---------------------------------------
                                                                                  1997           1996           1995
                                                                                ---------      ---------      ---------
                                                                                              (THOUSANDS)
                                TOTALS
<S>                                                                             <C>            <C>            <C>      
Future cash flows .........................................................     $ 556,647      $ 887,100      $ 350,653
Future costs:
     Production ...........................................................      (207,397)      (323,288)      (145,510)
     Development ..........................................................       (43,863)       (25,469)       (16,806)
                                                                                ---------      ---------      ---------

Future net cash flows before income taxes .................................       305,387        538,343        188,337
Future income taxes .......................................................        32,200        144,836             --
                                                                                ---------      ---------      ---------
Future net cash flows .....................................................       273,187        393,507        188,337
10% annual discount for estimated timing of
     cash flows ...........................................................       (97,264)      (165,273)       (75,041)
                                                                                ---------      ---------      ---------

Standardized measure of discounted net cash flows .........................     $ 175,923      $ 228,234      $ 113,296
                                                                                =========      =========      =========
</TABLE>

Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved
     Reserves (In Thousands)

<TABLE>
<CAPTION>
                                                                                            YEARS ENDED DECEMBER 31,
                                                                                     ---------------------------------------
                                                                                       1997            1996           1995
                                                                                     ---------      ---------      ---------
<S>                                                                                  <C>            <C>            <C>      
                                                                                                    (THOUSANDS)
                             UNITED STATES
Increase (decrease):
     Purchase of minerals-in place .............................................     $  22,753      $  49,966      $  77,343
     Extensions and discoveries and improved recovery, net
        of future production and development costs .............................        69,140         25,910          9,799
     Accretion of discount .....................................................        22,823         11,330          3,678
     Net change in sales prices net of production costs ........................      (170,943)       108,160         (3,422)
     Changes in estimated future development costs .............................         2,515          4,187         (2,419)
     Revisions of quantity estimates ...........................................       (17,890)        29,485         (2,855)
     Net change in income taxes ................................................        63,408        (83,570)            --
     Sales, net of production costs ............................................       (42,271)       (32,146)       (11,338)
     Sales of minerals in place ................................................       (29,975)        (1,330)            --
     Changes of production rates (timing) and other ............................        26,092          2,946          5,731
                                                                                     ---------      ---------      ---------

        Net increase (decrease) ................................................       (54,348)       114,938         76,517

     Standardized measure of discounted future net cash flows:
            Beginning of period ................................................       228,234        113,296         36,779
                                                                                     ---------      ---------      ---------

            End of period ......................................................     $ 173,886      $ 228,234      $ 113,296
                                                                                     =========      =========      =========
</TABLE>



                                      F-25
<PAGE>   58

                              COSTILLA ENERGY, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                           YEARS ENDED DECEMBER 31,
                                                                   ---------------------------------------
                                                                     1997           1996           1995
                                                                   ---------      ---------      ---------
                                                                                 (THOUSANDS)
<S>                                                                <C>            <C>            <C>      
                                MOLDOVA
Increase (decrease):
     Purchase of minerals-in place ...........................     $      --      $      --      $      --
     Extensions and discoveries and improved recovery, net
        of future production and development costs ...........         2,576             --             --
     Accretion of discount ...................................            --             --             -- 
     Net change in sales prices net of production costs ......            --             --             --
     Changes in estimated future development costs ...........            --             --             --
     Revisions of quantity estimates .........................            --             --             --
     Net change in income taxes ..............................          (539)            --             --
     Sales, net of production costs ..........................            --             --             --
     Sales of minerals in place ..............................            --             --             --
     Changes of production rates (timing) and other ..........            --             --             --
                                                                   ---------      ---------      ---------

        Net increase (decrease) ..............................         2,037             --             -- 

     Standardized measure of discounted future net cash flows:
            Beginning of period ..............................            --             --             --
                                                                   ---------      ---------      ---------

            End of period ....................................     $   2,037      $      --      $      --
                                                                   =========      =========      =========

                                TOTALS
Increase (decrease):
     Purchase of minerals-in place ...........................     $  22,753      $  49,966      $  77,343
     Extensions and discoveries and improved recovery, net
        of future production and development costs ...........        71,716         25,910          9,799
     Accretion of discount ...................................        22,823         11,330          3,678
     Net change in sales prices net of production costs ......      (170,943)       108,160         (3,422)
     Changes in estimated future development costs ...........         2,515          4,187         (2,419)
     Revisions of quantity estimates .........................       (17,890)        29,485         (2,855)
     Net change in income taxes ..............................        62,869        (83,570)            --
     Sales, net of production costs ..........................       (42,271)       (32,146)       (11,338)
     Sales of minerals in place ..............................       (29,975)        (1,330)            --
     Changes of production rates (timing) and other ..........        26,092          2,946          5,731
                                                                   ---------      ---------      ---------

        Net increase (decrease) ..............................       (52,311)       114,938         76,517

     Standardized measure of discounted future net cash flows:
            Beginning of period ..............................       228,234        113,296         36,779
                                                                   ---------      ---------      ---------

            End of period ....................................     $ 175,923      $ 228,234      $ 113,296
                                                                   =========      =========      =========
</TABLE>

     The 1997 future cash flows shown above include amounts attributable to
proved undeveloped reserves requiring approximately $42.5 million of future
development costs. If these reserves are not developed, the standardized measure
of discounted future net cash flows for 1997 shown above would be reduced by
approximately $42.3 million.

                                      F-26
<PAGE>   59


                                 EXHIBIT INDEX

<TABLE>
<CAPTION>


             EXHIBIT
             NUMBER          DESCRIPTION OF EXHIBIT
             -------         ----------------------
            <S>              <C>                                                      
             *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 Exhibit 4.2)

             *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            First Supplemental Indenture dated January 16, 1998
                             by and between State Street Bank and Trust Company,
                             as Trustee, and the Company, as Issuer (including 
                             form of Global Certificate)

             #4.4            Form of Note

            **4.5            Form of Stock Certificate

            *10.1            Lease Agreement dated January 12, 1996 between 
                             Independence Plaza,Ltd. and Costilla Energy, L.L.C.

            *10.2            Concession Agreement dated July 6, 1995 between the
                             Government of the Republic of Moldova and Resource
                             Development Company Ltd., L.L.C. (DE)

            *10.3            Consolidation Agreement dated October 8, 1996

            *10.4            1996 Stock Option Plan

            *10.5            Employment Agreement between the Company and Bobby 
                             W. Page effective June 30, 1996

            *10.6            Employment Agreement between the Company and Cadell
                             S. Liedtke effective October 8, 1996


</TABLE>


<PAGE>   60


<TABLE>
<CAPTION>

             EXHIBIT
             NUMBER          DESCRIPTION OF EXHIBIT
             -------         ----------------------
            <S>              <C>
            *10.7            Employment Agreement between the Company and 
                             Michael J. Grella effective October 8, 1996

            *10.8            Employment Agreement between the Company and Henry 
                             G. Musselman effective October 8, 1996

            *10.9            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

           *10.10            Bonus Incentive Plan

           +10.11            First and Second Amendments to Stock Option Plan of
                             Costilla Energy, Inc.

           +10.12            First Amendment to Outside Directors Stock Option
                             Plan of Costilla Energy, Inc.

           +10.13            First, Second and Third Amendments to Bonus 
                             Incentive Plan of Costilla Energy, Inc.

          ++10.14            Purchase and Sale Agreement dated July 2, 1997 
                             between Ballard Petroleum LLC, as seller, and the
                             Company, as buyer

          ++10.15            Acquisition and Exploration Agreement effective as 
                             of July 1, 1997 by and between Ballard Petroleum,
                             LLC and the Company

           #10.16            Purchase Agreement dated January 14, 1998 among BT 
                             Alex. Brown Incorporated and Prudential Securities
                             Incorporated, as Initial Purchasers, and the
                             Company, as Issuer

           #10.17            Registration Rights Agreement dated January 16, 
                             1998 among BT Alex. Brown Incorporated and
                             Prudential Securities Incorporated, as Initial
                             Purchasers, and the Company, as Issuer

           #10.18            Amendment to Employment Agreement between the 
                             Company and Cadell S. Liedtke dated April 15, 1997

           #10.19            Amendment to Employment Agreement between the 
                             Company and Michael J. Grella dated April 15, 1997

           #10.20            Amendment to Employment Agreement between the 
                             Company and Henry G. Musselman dated April 15,
                             1997

           #10.21            Second Amendment to Employment Agreement between  
                             the Company and Henry G. Musselman dated April 15,
                             1997

           #10.22            Amendment to Employment Agreement between the 
                             Company and Bobby W. Page dated April 15, 1997

            #12.1            Computation of Ratio of Adjusted EBITDA to Interest
                             Expense

            #21.1            Subsidiaries of the Registrant


</TABLE>


<PAGE>   61

<TABLE>
<CAPTION>

            EXHIBIT
            NUMBER           DESCRIPTION OF EXHIBIT
            -------          ----------------------
            <S>              <C>
            #23.1            Consent of KPMG Peat Marwick LLP

            #23.2            Consent of Williamson Petroleum Consultants

            #23.3            Consent of W. Scott Epley, P.E.

            #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

</TABLE>


         *        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.

         +        Incorporated by reference to the Company's  Quarterly  Report
                  on Form 10-Q for the quarter ended June 30, 1997.

         ++       Incorporated by reference to the Company's Quarterly Report on
                  Form 10-Q for the quarter ended September 30, 1997.

         #        Filed herewith.