<PAGE>   1



                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, 1998
                       Commission File Number : 001-14575

                          VISTA ENERGY RESOURCES, INC.
              ----------------------------------------------------
             (Exact name of registrant as specified in its charter)

                Delaware                           75-2766114
                --------                           ----------
     (State or other jurisdiction of              (I.R.S. Employer
      incorporation or organization)              Identification No.)

             550 West Texas Avenue, Suite 700, Midland, Texas 79701
             ------------------------------------------------------
                    (Address of principal executive offices)

      Registrant's telephone number, including area code - (915) 570-5045

      Securities registered pursuant to Section 12(b) of the Exchange Act:
             Common Stock, $.01 Par Value              American Stock Exchange
       Common Stock Warrants at $4.00 per share        American Stock Exchange

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

         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 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. [X]

         The aggregate market value of common stock held by non-affiliates of
the registrant as of December 31, 1998 was $12,496,451, computed using $2.125,
the price at which the stock sold on said date.

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:

              Class                            Outstanding as of March 15, 1999
    Common stock, $.01 par value                         16,312,336


                      DOCUMENTS INCORPORATED BY REFERENCE
         Part III of the report is incorporated by reference to the
Registrant's definitive Proxy Statement relating to its Annual Meeting of
Stockholders, which will be filed with the Commission no later than April 30,
1999.


<PAGE>   2

                          VISTA ENERGY RESOURCES, INC.
             FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998


                                     INDEX

<TABLE>
<CAPTION>
PART I.                                                                                Page
                                                                                       ----
<S>          <C>                                                                       <C>
Item 1       Business Description .................................................      3
Item 2       Description of Properties ............................................     12
Item 3       Legal Proceedings ....................................................     21
Item 4       Submission of Matters to a Vote of Security Holders ..................     21


PART II

Item 5       Market for Common Equity and Related Stockholder Matters .............     21
Item 6       Selected Financial Data ..............................................     22
Item 7       Management's Discussion and Analysis of Financial Condition and
                 Results of Operations ............................................     23
Item 7a      Quantitative and Qualitative Disclosures About Market Risk ...........     32
Item 8       Financial Statements and Supplementary Data ..........................     34
Item 9       Changes in and Disagreements with Accountants on Accounting
                 and Financial Disclosure .........................................     34


PART III.

Item 10      Directors and Executive Officers of the Registrant ...................     34
Item 11      Executive Compensation ...............................................     34
Item 12      Security Ownership of Certain Beneficial Owners and Management .......     34
Item 13      Certain Relationships and Related Transactions .......................     34



PART IV

Item 14      Exhibits, Financial Statement Schedules and Reports on Form 8-K ......     35
Item 15      Other Information ....................................................     37
</TABLE>


                                       2
<PAGE>   3

                          VISTA ENERGY RESOURCES, INC.

                        1998 Annual Report on Form 10-K

                                     PART I

ITEM 1. BUSINESS DESCRIPTION

GENERAL

         Vista Energy Resources, Inc. ("Vista" or the "Company") was
incorporated in Delaware in May 1998 for the purpose of consolidating and
continuing the activities previously conducted by Vista Resources Partners,
L.P., a privately held Texas limited partnership (the "Vista Partnership"), and
Midland Resources, Inc., a Texas corporation ("Midland Resources"). Vista is an
independent energy company engaged in the acquisition, development and
exploration of oil and natural gas properties. The Company has experienced
significant growth in reserves, production and cash flow by acquiring and
exploiting producing properties primarily in the Permian Basin of West Texas,
Southeastern New Mexico and the onshore Gulf Coast region of South Texas.

          In 1998, the Company completed two transactions that substantially
impacted the Company. On October 28, 1998, the Company completed its merger with
Midland Resources (the "Midland Merger"), an independent oil and gas corporation
engaged in the exploration, acquisition, development and production of oil and
gas properties primarily located in the Permian Basin. Pursuant to the terms of
the Vista Exchange Agreement dated as of June 15, 1998 (the "Exchange
Agreement"), the Company acquired all of the outstanding partnership interests
of the Vista Partnership and Vista Resources I, Inc., its general partner, in
exchange for shares of common stock, par value $.01 per share (the "Common
Stock") of the Company (the "Conversion"). The Conversion and other transactions
contemplated by the Exchange Agreement were consummated immediately prior to the
closing of the Midland Merger. As a result of the Conversion and the Midland
Merger, Midland Resources' security holders acquired 4,470,123 shares, or 27.3
percent of the outstanding Common Stock of the Company while security holders of
the Vista Partnership acquired 11,903,506 shares, or 72.7 percent of the
outstanding Common Stock of the Company. Also as a result of the Conversion and
the Midland Merger, the Company's Common Stock became publicly traded on the
American Stock Exchange on October 29, 1998. References to "Vista" or the
"Company" include Vista Energy Resources, Inc. and its predecessors and
subsidiaries, including the Vista Partnership, Vista Resources, Inc., Vista
Resources I, Inc. and Midland Resources.

          On December 18, 1998 (effective date of October 1, 1998), the Company
acquired working interests ranging from 65 percent to 85 percent in a group of
oil and gas producing leases from IP Petroleum Company, Inc. ("IP Petroleum")
and certain of its working interest partners. These leases are located primarily
in the War-Wink area of Ward and Winkler Counties, Texas. The interests were
acquired for a cash purchase price of $19.1 million (the "IP Acquisition").  The
Midland Merger and the IP Acquisition are herein referred to as the "1998
Acquisitions."

         As of December 31, 1998, the Company had estimated net proved reserves
of approximately 10.5 MBbls of oil and 31.6 Bcf of natural gas, or an aggregate
of 15.7 MBOE with an SEC PV-10 of $50.2 million. As of 



                                       3
<PAGE>   4



December 31, 1998, Vista operated 547 gross oil and gas wells. The Company's
operated properties represent approximately 93 percent of its proved reserve
base at December 31, 1998. The Company's emphasis on controlling the operation
of its properties enables the Company to better manage expenses, capital
allocation and other aspects of development and exploration.

         The Company's goals are to substantially grow its reserves,
production, cash flow and net income per share through (i) the acquisition of
producing properties that provide development and exploratory drilling
potential; (ii) the exploitation and development of its existing reserve base;
(iii) the exploration for oil and gas reserves; and (iv) the implementation and
maintenance of a low operating and overhead cost structure.

         Vista's principal executive offices are located at 550 West Texas
Avenue, Suite 700, Midland, Texas 79701.

CURRENT OPERATING ENVIRONMENT

         The oil and gas industry is affected by many factors that the Company
typically cannot control. Crude oil prices are generally determined by global
supply and demand. After sinking to a five-year low at the end of 1993, oil
prices reached their highest levels since the 1990 Persian Gulf War during
fourth quarter 1996 and January 1997. Crude oil prices ranged from $17 to $20
during most of 1997, then declined to a $16 average in December 1997. Crude oil
prices continued to decline throughout 1998, dropping to a West Texas
Intermediate posted price of $8.00 per barrel in December 1998, the lowest
level since 1978. This decline has been caused by low demand, as well as the
failure of OPEC, at its November 1998 meeting, to further reduce production
quotas. Low demand has been caused by warmer than normal winter temperatures
and a slow recovery in Asian economies. Although oil prices have improved to
some degree in March 1999, current prices remain substantially lower than the
levels achieved in 1997.

         Natural gas prices are influenced by national and regional supply and
demand, which is often dependent upon weather conditions. Natural gas competes
with alternative energy sources as a fuel for heating and the generation of
electricity. Generally because of colder weather, storage concerns, and U.S.
economic growth, prices remained relatively high during most of 1996 and 1997,
reaching their highest levels since 1985. Gas prices declined, however, in
December 1997, and have remained lower throughout 1998, primarily because the
winters of 1997-1998 and 1998-1999 were abnormally mild in the central and
eastern United States.

MARKETING

         The Company's oil and natural gas production is principally sold to
pipelines, marketers, refiners and other purchasers having access to natural
gas pipeline facilities near its properties and the ability to truck oil to
local refineries or oil pipelines. The Company's ability to market its oil and
gas depends on many factors beyond its control, including the extent of
domestic production and imports of oil and gas, the proximity of the Company's
gas production to pipelines, the available capacity in such pipelines, the
demand for oil and gas, the effects of weather and the effects of state and
federal regulation. The Company cannot assure that it will always be able to
market all of its production or obtain favorable prices. The Company does not
believe, however, that the loss of any of its oil or gas purchases would have a
material adverse impact on its results of operations or financial condition.



                                       4
<PAGE>   5


COMPETITION

         The Company encounters competition from other oil and gas companies in
all areas of its operations, including the acquisition of producing properties
and oil and gas leases, marketing of oil and gas and obtaining goods, services
and resources. The Company's competitors range from individual oil and gas
operators to the major oil and gas firms. Since many of the competitors are
larger with more human and monetary resources and are sometimes able to pay
more for productive oil and gas properties, the Company's ability to acquire
additional properties and discover reserves will be dependent upon its ability
to evaluate and select suitable properties and to consummate the transactions
in a highly competitive market. Competition is also presented by alternative
fuel sources including heating oil and other fossil fuels. Because of the
long-lived nature of the Company's oil and gas reserves and management's
expertise in exploiting these reserves, management believes that it is
effective in competing in the market.

ABANDONMENT COSTS

         The Company is responsible for payment of its working interest share
of plugging and abandonment costs on its oil and natural gas properties. Based
on its experience, the Company anticipates that the ultimate aggregate salvage
value of lease and well equipment located on its properties will exceed the
costs of abandoning such properties. There can be no assurance, however, that
the Company will be successful in avoiding additional expenses in connection
with the abandonment of any of its properties. In addition, abandonment costs
and their timing may change due to many factors including actual production
results, inflation rates and changes in environmental laws and regulations.

TITLE TO PROPERTIES

         Title to the Company's oil and natural gas properties is subject to
royalty, overriding royalty, carried interest and other similar interests and
contractual arrangements customary in the oil and natural gas industry, to
liens incident to operating agreements and for current taxes not yet due and
other comparatively minor encumbrances. As is customary in the oil and natural
gas industry, only a perfunctory investigation as to ownership is conducted at
the time undeveloped properties believed to be suitable for drilling are
acquired. Prior to the commencement of drilling on a tract, a detailed title
examination is conducted and curative work is performed with respect to known
significant title defects.

INSURANCE

         The oil and gas industry is subject to many risks, including the risk
that no commercially productive reservoirs will be discovered, or if reserves
are found, that they will not be in sufficient quantities to be economical for
recovery. The costs of drilling, completing and operating wells is often
uncertain. The Company's drilling operations may be curtailed, delayed or
canceled because of numerous outside factors including title problems, weather
conditions, mechanical problems, governmental requirements and shortages or



                                       5
<PAGE>   6

delays in deliveries of equipment and services. The Company has risk inherent
in normal oil and gas operations such as fire, natural disasters, explosions,
blowouts, cratering, pipeline ruptures and spills, any of which could result in
the loss of oil and gas, environmental pollution, personal injury claims and
property damage. Any unsuccessful drilling activities or accidents may have an
adverse effect on the Company's future results of operations and financial
condition.

          The Company maintains insurance against some, but not all, of the
risks described above. The Company may elect to self-insure in circumstances in
which management believes that the cost of insurance is excessive relative to
the risks presented. The occurrence of an event that is not covered, or not
fully covered, by insurance could have a material adverse effect on the
Company's financial condition and results of operations.

EMPLOYEES

         As of December 31, 1998, the Company had 28 full-time employees, none
of whom is represented by a labor union. The Company considers its relations
with its employees good.

OFFICE FACILITIES

         The Company currently leases approximately 10,963 square feet of
office space at 550 West Texas Avenue, Suite 700 Midland, Texas under an Office
Lease dated October 10, 1996, by and between the Company and Fasken Center,
Ltd. (as amended from time to time, the "Lease"). The Lease is a typical office
lease containing standard and customary lease provisions and runs from January
1, 1997, through August 31, 2002. The Company also has office space leased at
616 F.M. 1960 West, Suite 600, Houston, Texas 77090. This space was previously
leased by Midland Resources. The Company is currently attempting to sublease
the space in Houston since it conducts no operations in the Houston area. This
lease expires in 2002.

GOVERNMENTAL REGULATION

         General

         There have been, and continue to be, numerous federal and state laws
and regulations governing the oil and gas industry that are often changed in
response to the current political or economic environment. Compliance with this
regulatory burden is often difficult and costly and may carry substantial
penalties for noncompliance. The following are some specific regulations that
may affect the Company. The Company cannot predict the impact of these or
future legislative or regulatory initiatives.

         In 1992, FERC issued Order Nos. 636 and 636-A, requiring operators of
pipelines to unbundle transportation services from sales services and allow
customers to pay for only the services they require, regardless of whether the
customer purchases gas from such pipelines or from other suppliers. The United
States Court of Appeals upheld the unbundling provisions and other components
of FERC's orders, but remanded several issues to FERC for further explanation.
On February 27, 1997, FERC issued Order No. 636-C, addressing the court's
concern. Petitions for rehearing on Order No. 636-C were denied on May 28,
1998. FERC's order remains subject to judicial review and may be changed as a
result of that review. Although FERC's regulations should generally facilitate
the transportation of gas produced from the Company's



                                       6
<PAGE>   7
properties and the direct access to end-user markets, the impact of these
regulations on marketing the Company's production or on its gas transportation
business cannot be predicted. The Company, however, does not believe that it
will be affected any differently than other natural gas producers and marketers
with which it competes.

         Federal Regulation of Oil

         Sales of crude oil, condensate and natural gas liquids are not
currently regulated and are made at market prices. The net price received from
the sale of these products is affected by market transportation costs. A
significant part of the Company's oil production is transported by pipeline. The
Energy Policy Act of 1992 required FERC to adopt a simplified ratemaking
methodology for interstate oil pipelines. In 1993 and 1994, FERC issued Order
Nos. 561 and 561-A, adopting rules that establish new rate methods for such
pipelines. Under the new rules, effective January 1, 1995, interstate oil
pipelines can change rates based on an inflation index, though other rate
mechanisms may be used in specific circumstances. The United States Court of
Appeals upheld FERC's orders in 1996. These rules have had little, if any,
effect on the Company with respect to the cost of moving oil to market.

         State Regulation

         Oil and gas operations are subject to various types of regulation at
the state and local levels. Such regulation includes requirements for drilling
permits, the method of developing new fields, the spacing and operations of
wells and waste prevention. The production rate may be regulated and the
maximum daily production allowable from oil and gas wells may be established on
a market demand or conservation basis. These regulations may limit production
by well and the number of wells or locations that can be drilled.

         The Company may become party to agreements relating to the
construction or operations of pipeline systems for the transportation of
natural gas. To the extent that such gas is produced, transported and consumed
wholly within one state, such operations may, in certain instances, be subject
to the state's administrative authority charged with regulating pipelines. The
rates that can be charged for gas, the transportation of gas, and the
construction and operation of such pipelines would be subject to the
regulations governing such matters. Certain states have recently adopted
regulations with respect to gathering systems, and other states are considering
regulations with respect to gathering systems. New regulations passed have not
had a material effect on the operations of the Company's gathering systems, but
the Company cannot predict whether any further rules will be adopted or, if
adopted, the effect these rules may have on its gathering systems.

ENVIRONMENTAL MATTERS

         The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to
environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment, and
relating to safety and health. There has been a trend to even stricter
standards than are currently in place, and this trend will likely continue.
Governmental authorities have the power to enforce compliance with their
regulations and violators are subject to fines, injunction or both. The Company
is subject to such laws as those governing the disposal of hazardous waste,



                                       7
<PAGE>   8

spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters and the discharge of produced
waters into navigable waters.

         Regulations are currently being developed under federal and state laws
concerning oil pollution prevention and other matters that may impose
additional regulatory burdens on the Company. The implementation of new or
modification of existing laws or regulations could have a material adverse
effect on the Company. The discharge of oil, gas or other pollutants into the
air, soil or water may give rise to significant liabilities on the part of the
Company to the government and third parties, and may require the Company to
incur substantial costs for remediation. The Company has acquired leasehold
interests in numerous properties that for many years have produced oil and gas.
The previous owners of these interests may have used operating and disposal
practices that were standard in the industry at the time. Also, the Company has
purchased interests in properties that are operated by third parties over which
the Company has no control. Notwithstanding, the Company's lack of control over
the properties operated by others, the failure of the operator to comply with
applicable environmental regulations may, in some circumstances, materially
adversely impact the Company.

         In the opinion of the management, the Company is in substantial
compliance with current applicable environmental laws and regulations, and the
Company has no material commitments for capital expenditures to comply with
existing environmental requirements. Nevertheless, changes in existing
environmental laws and regulations or in interpretations thereof could have a
significant adverse effect on the Company.

GLOSSARY OF OIL AND GAS TERMS

         The following are abbreviations and definitions of terms commonly used
in the oil and gas industry that are used in this Report.

         "Bbl" means a barrel of 42 U.S. gallons.

         "Bcf" means billion cubic feet.

         "BOE" means barrels of oil equivalent, converting volumes of natural
gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one
Bbl of oil.

         "completion" means the installation of permanent equipment for the
production of oil or gas.

         "development well" means a well drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive.

         "dry hole" or "dry well" means a well found to be incapable of
producing hydrocarbons in sufficient quantities such that proceeds from the
sale of such production exceed production expenses and taxes.

         "exploratory well" means a well drilled to find and produce oil or gas
reserves not classified as proved, to find a new production reservoir in a
field previously found to be productive of oil or gas in another reservoir or
to extend a known reservoir.



                                       8
<PAGE>   9

         "farm-in" means an agreement pursuant to which the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in."

         "gas" means natural gas.

         "gross" when used with respect to acres or wells, refers to the total
acres or wells in which the Company has a working interest.

         "infill drilling" means drilling of an additional well or wells
provided for by an existing spacing order to more adequately drain a reservoir.

         "MBbl" means thousand Bbls.

         "MBOE" means thousand BOE.

         "Mcf" means thousand cubic feet.

         "MMBOE" means million BOE.

         "MMBtu" means one million British Thermal Units. British Thermal Units
means that quantity of heat required to raise the temperature of one pound of
water by one degree Fahrenheit.

         "MMcf" means million cubic feet.

         "net" when used with respect to acres or wells, refers to gross acres
or wells multiplied, in each case, by the percentage working interest owned by
the Company.

         "net production" means production that is owned by the Company less
royalties and production due others.

         "NGL" means natural gas liquid.

         "operator" means the individual or company responsible for the
exploration, development and production of an oil or gas well or lease.

         "present value" when used with respect to oil and gas reserves, means
the estimated future gross revenues to be generated from the production of
proved reserves calculated in accordance with the guidelines of the SEC, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation (except to the extent a
contract specifically provides otherwise), without giving effect to
non-property related expenses such as general and administrative expenses, debt
service, future



                                       9
<PAGE>   10

income tax expense and depreciation, depletion and amortization, and discounted
using an annual discount rate of 10 percent.

         "productive wells" or "producing wells" consist of producing wells and
wells capable of production, including wells waiting on pipeline connections.

         "proved developed reserves" means reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.

         "proved reserves" means the estimated quantities of crude oil, natural
gas and NGLs which upon analysis of geological and engineering data appear with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

         (i)      Reservoirs are considered proved if economic producibility is
                  supported by either actual production or conclusive formation
                  tests. The area of a reservoir considered proved includes (A)
                  that portion delineated by drilling and defined by gas-oil
                  and/or oil-water contacts, if any; and (B) the immediately
                  adjoining portions not yet drilled, but which can be
                  reasonably judged as economically productive on the basis of
                  available geological and engineering data. In the absence of
                  information on fluid contacts, the lowest known structural
                  occurrence of hydrocarbons controls the lower proved limit of
                  the reservoir.

         (ii)     Reserves which can be produced economically through
                  application of improved recovery techniques (such as fluid
                  injection) are included in the "proved" classification when
                  successful testing by a pilot project, or the operation of an
                  installed program in the reservoir, provides support for the
                  engineering analysis on which the project or program was
                  based.

         (iii)    Estimates of proved reserves do not include the following:
                  (A) oil that may become available from known reservoirs but
                  is classified separately as "indicated additional reserves";
                  (B) crude oil, natural gas and NGLs, the recovery of which is
                  subject to reasonable doubt because of uncertainty as to
                  geology, reservoir characteristics or economic factors; (C)
                  crude oil, natural gas, and NGLs, that may occur in undrilled
                  prospects; and (D) crude oil, natural gas and NGLs that may
                  be recovered from oil shales, coal, gilsonite and other such
                  reserves.

         "proved undeveloped reserves" means 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 completion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive



                                      10
<PAGE>   11

formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.

         "recompletion" means the completion for production of an existing well
bore in another formation from that in which the well has been previously
completed.

         "reserves" means proved reserves.

         "reservoir" means a porous and permeable underground formation
containing a natural accumulation of producible oil and/or gas that is confined
by impermeable rock or water barriers and is individual and separated from the
reservoirs.

         "royalty" means an interest in an oil and gas lease that gives the
owner of the interest the right to receive a portion of the production from the
leased acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalties may be either landowner's royalties,
which are reserved by the owner of the leased acreage at the time the lease is
granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner.

         "2-D seismic" means an advanced technology method by which a cross
section of the earth's subsurface is created through the interpretation of
reflecting seismic data collected along a single source profile.

         "3-D seismic" means an advanced technology method by which a three
dimensional image of the earth's subsurface is created through the
interpretation of reflection seismic data collected over surface grid. 3-D
seismic surveys allow for a more detailed understanding of the subsurface than
do conventional surveys and contribute significantly to field appraisal,
development and production.

         "working interest" means an interest in an oil and gas lease that
gives the owner of the interest the right to drill for and produce oil and gas
on the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations. The share of production to which a working
interest owner is entitled will always be smaller than the share of costs that
the working interest owner is required to bear, with the balance of the
production accruing to the owners of royalties.

         "workover" means operations on a producing well to restore or increase
production.



                                      11
<PAGE>   12



ITEM 2. DESCRIPTION OF PROPERTIES

         The following table summarizes the proved reserves and discounted
present value, before income tax, of proved reserves by the Company's major
operating areas at December 31, 1998:

<TABLE>
<CAPTION>
                                                         
                                                              Discounted       
                                                             Present Value     
                                 Proved Reserves             Before Income     
                         ---------------------------             Tax of        
                          Oil (Bbls)       Gas (Mcf)        Proved Reserves    
                         -----------      ----------     ---------------------
<S>                      <C>             <C>            <C>              <C>  
Permian Basin             10,214,636      23,713,649     $44,303,668      88.2%
South Texas                  226,963       7,910,864       5,859,855      11.7%
Other                         17,171          21,454          73,391       0.1%
                         -----------     -----------     -----------     -----

Total                     10,458,770      31,645,967     $50,236,914     100.0%
                         ===========     ===========     ===========     =====
</TABLE>


PERMIAN BASIN

         Approximately 90 percent of the Company's reserves are located in the
Permian Basin of West Texas and Southeastern New Mexico. Vista's single largest
concentration of reserves (36 percent of the Company's total proved reserves)
is located in three contiguous fields in the Delaware Basin. These fields hold
numerous opportunities for development of new drilling locations as well as
behind pipe reserves at relatively shallow depths, with relatively small
capital expenditures required for such development. An additional 40 percent of
Vista's reserves are located in several prolific fields in West Texas including
Howard Glasscock, Jameson, Sharon Ridge, Brahaney and Keystone. Each of these
large fields can be characterized by multiple reservoirs, most of which are
fairly shallow, with substantial primary and secondary reserves remaining to be
recovered. The Company is attracted to these types of fields due to the huge
reserve base remaining and the long-lived nature of the reserves, as well as
the economies of scale afforded by establishing core areas of operations.
         
         War-Wink, Caprito and Rhoda Walker Fields, Ward and Winkler Counties,
Texas

         The Delaware Basin is a large depositional basin in the southwestern
portion of the Permian Basin approximately 70 miles west of Midland, Texas.
Vista substantially increased its position in this basin with the purchase of
IP Petroleum's Warwink field properties located in Ward and Winkler Counties,
Texas, effective October 1, 1998. This purchase of 65 producing wells brought
the Company's overall well count in the Delaware basin to over 100 wells when
added to the Company's existing assets in the nearby Rhoda Walker and Caprito
fields. Production net to Vista from these leases is approximately 1,150 BOE
per day or about 30 percent of Vista's production.

         In addition, these leases include over 3,300 net undeveloped acres
that offer numerous drilling opportunities. The Company has 15 proved
undeveloped locations identified at this time and an additional 20 probable
drilling locations. Total proved reserves attributable to these leases are
estimated to be 5,592 MBOE (36 percent of Vista's total proved reserves). The
primary producing interval in these three fields is the Cherry



                                      12
<PAGE>   13


Canyon sand formation, which is the middle member of the Delaware Mountain
Group. The Cherry Canyon is a series of sand and shale formations ranging in
depth from 5,800 to 7,200 feet. The Company has identified productive sands
behind pipe in nearly 50 wells on its leases in the basin. These unexploited
reserves can accelerate production from these fields with minor capital
outlays. Accordingly, the Company plans to spend a substantial amount of its
capital budget for 1999 in this area.

         Howard Glasscock Field, Howard County, Texas

         This field is located 60 miles east of Midland, Texas, and was
discovered in 1925. The field has produced over 439 MMBbls of oil from wells
less than 4,000 feet deep. The Company owns a 100 percent working interest in
ten of the eleven leases (1,675 net acres) it operates in this field. The field
contains Vista's greatest concentration of proved undeveloped reserves (2,085
MBOE, net) and its second largest concentration of proved producing reserves
(797 MBOE, net). Accordingly, the Company plans to continue to devote a
substantial portion of its capital budget and operating resources to the
ongoing development of these low risk reserves. Since acquiring these leases
less than three years ago, the Company has increased gross production by over
300 percent and expanded or initiated new secondary recovery projects in the
Glorieta formation, the San Andres formation and the Middle Clearfork formation
on six of its leases in the field. In addition to future production increases
from secondary recovery projects, Vista expects continued growth in production
in this area from development drilling of the San Andres formation on several
of its leases. Vista owns an interest in 52 producing wells in this field.

         Jameson (Strawn) Field, Coke and Sterling Counties, Texas

         This field is located in Coke and Sterling Counties, Texas. The
Company owns and operates 58 active wells with a combined 1998 average
production rate of approximately 125 BOPD and 1,200 Mcfd. At the time the
Company acquired the Jameson properties in 1992, there were 21 gross wells
which were shut-in for various reasons by the former operator. The Company has
returned 15 of those wells to production and has converted nearly 40 percent of
the wells from producing via conventional pumping unit to a less expensive
plunger lift method of artificial lift. The low lifting cost and high net
revenue interest on this lease results in high operating margins in this field.
The Company owns a 100 percent working interest in this field which includes
7,360 acres under lease. Net revenue interests on individual leases range from
90 percent to 92 percent. Net reserves are estimated at over 700 MBOE from this
field which includes fifteen proved undeveloped locations. In addition to these
proved reserves, there are 20 additional possible drilling locations.



                                      13
<PAGE>   14

         Brahaney Field, Yoakum County, Texas

         Vista first acquired three leases in this field as part of the $6.1
million acquisition of E.G. Operating Co., a division of FGL, Inc. ("E.G.") in
1996. At that time the properties produced 50 Bbls of oil per day from four
wells producing from the Wolfcamp and Devonian formations. In late 1998, Vista
made a significant new discovery when two marginal wells in the field were
recompleted into a new reservoir that had not previously produced in the area.
Based on those results, additional leases with similar potential were acquired
in late December, 1998. By year end 1998, Vista operated seven producing wells
located on 546 net acres in the field. Net production at the end of the year
was 220 BOPD, an increase of 400 percent from the prior year. Proved producing
and non-producing reserves are estimated at 525 MBOE for the field.

         Sharon Ridge Field, Scurry County, Texas

         This field is located 80 miles northeast of Midland, Texas, and has
produced over 100 MMBbls of oil from depths as shallow as 1,700 feet. Vista
owns a 100 percent working interest in the two leases (227 net acres) it
operates in this field, the Hardee lease and House lease. These two adjacent
properties are located in the middle of the Sharon Ridge (1,700 feet) field and
are surrounded by successful waterfloods. Since acquiring these properties in
1996, the Company has successfully drilled the remaining locations (nine wells)
and implemented a full scale waterflood on the two leases. As of January 1998,
through infill drilling and early secondary response, production has increased
over 300 percent, and Vista expects a continued gradual increase in production
as the reservoir is repressured and oil is swept towards the producing wells.
Vista operates 17 producing wells in this field with net proved producing
reserves of 367 MBOE.

         Keystone Field, Winkler County, Texas

         The Keystone field is located 50 miles west of Midland, Texas, and
produces from nine different formations with depths ranging from 3,000 feet to
9,000 feet. Since discovery in 1927, the various reservoirs of the Keystone
field have produced over 320 MMbls of oil and 693 Bcf of natural gas. Vista
owns a 100 percent working interest in each of the two leases it operates in
the field, the Waddell lease (2,232 net acres, 35 net producing wells) and the
Keystone Cattle Company lease (640 net acres, 21 net producing wells). The
field has net proved reserves of 485 MBOE. In addition, there are substantial
probable reserves in the San Andres and Holt formations that should be
recovered through secondary recovery as well as probable gas reserves in the
shallow Yates formation.

         Latigo and Lakota 3D Seismic Exploration and Development Projects

         These projects were defined and acquired as 3-D seismic exploration
projects in 1995 in the Northwest Shelf area of the Permian Basin in Hockley
County, Texas. The seismic survey covered 12 square miles and resulted in the
leasing of approximately 4,890 acres. Two successful exploratory wells were
drilled in the Lakota project in 1997 at a cost to the Company of approximately
$1.6 million. Average daily production from the wells drilled in this project
in 1998 was 170 BOPD. The Company owns a 55 percent working interest in this
project. Recently Vista has elected to purchase additional existing seismic
data in the area and extend their



                                      14
<PAGE>   15

leasehold in several areas. Vista believes there are as many as six drill-ready
prospects on this acreage to develop once commodity prices improve.

SOUTH TEXAS

         North Rucias Field, Brooks County, Texas

         Vista operates two wells in this geologically complex field. The
Company's working interest in the Huerta lease (323 net acres, one well) is 50
percent, and its working interest in the Deluna lease (596 net acres, one well)
is 93 percent. Additionally, Vista also holds 758 net acres of leasehold under
primary term in the field. The principal producing formation in the field is
the Vicksburg formation at an approximate depth of 9,600 feet. Through 3-D
seismic, the Company has successfully identified untested Vicksburg fault
blocks in the immediate area of Vista's leasehold position. An existing 3-D
seismic survey covering our acreage is commercially available. Vista is
currently negotiating with industry partners for participation in funding 3-D
seismic purchases covering our leasehold in return for an interest in our
acreage position. The Vicksburg wells in the area average over 6 Bcf per well
in proved reserves. Vista expects to drill its first prospect here in late
1999.

         Orange Hill, South Field, Austin County, Texas

         Vista owns a 100 percent working interest in this 984 acre Hillboldt
lease which has one lower Wilcox well and one shallow Frio well producing a
combined 750 Mcfd. In 1998, Vista contributed a portion of its acreage and
entered into an Area of Mutual Interest ("AMI") agreement with another company
for the purpose of drilling additional lower Wilcox wells. The first well on
the AMI was successfully completed in the fourth quarter of 1998, and is
currently producing approximately 1.1 MMcfd. Two additional wells are scheduled
to be drilled in the second and fourth quarters of 1999. Gross reserves for
these wells is estimated to be 4 Bcf each with Vista owning a 33.34 percent
working interest in each. Total proved recoverable reserves for this field are
estimated to be 5.43 Bcfe (905 MBOE) net to Vista.



                                      15
<PAGE>   16





NET PRODUCTION, UNIT SALES AND PRODUCTION COSTS

         The following table summarizes the net oil and natural gas production
for the Company, the average sales price per barrel of oil and per Mcf of
natural gas produced and the average production (lifting) cost (including all
severance and ad valorem taxes) per unit of production for the years ended
December 31, 1998, 1997 and 1996:

<TABLE>
<CAPTION>
                                                                                         For the Years Ended December 31,
                                                                                     ----------------------------------------
                                                                                        1998           1997           1996
                                                                                     ----------     ----------     ----------
<S>                                                                                  <C>            <C>            <C>       
Revenues .......................................................................     $8,737,056     $8,874,961     $5,537,720
Costs and expenses:
      Production costs .........................................................      4,398,384      3,688,695      2,544,567
      Depletion ................................................................      3,014,707      2,169,098      1,272,316
      Exploration costs ........................................................         32,077         97,211        273,843
                                                                                     ----------     ----------     ----------
                                                                                      7,445,168      5,955,004      4,090,726
                                                                                     ----------     ----------     ----------
      Operating profit (excluding impairment, general and administrative
         and interest expenses and income taxes) ...............................     $1,291,888     $2,919,957     $1,446,994
                                                                                     ==========     ==========     ==========
Production:
      Oil (Bbls) ...............................................................        529,426        403,812        253,321
      Gas (Mcf) ................................................................      1,250,490        784,298        458,278
          Total (BOE) (a) ......................................................        737,841        534,528        329,701
Average Daily Production:
      Oil (Bbls) ...............................................................          1,450          1,107            693
      Gas (Mcf) ................................................................          3,426          2,148          1,255
                                                                                     ----------     ----------     ----------
          Total (BOE) (a) ......................................................          2,021          1,465            902
Average Oil Price (Per Bbl) ....................................................     $    12.25     $    17.63     $    18.04
Average Gas Price (Per Mcf) ....................................................     $     1.80     $     2.22     $     2.19
Costs (Per BOE) (a)
      Lease operating expense ..................................................     $     5.24     $     5.62     $     6.35
      Production taxes .........................................................     $      .72     $     1.28     $     1.37
                                                                                     ----------     ----------     ----------
          Total Production costs ...............................................     $     5.96     $     6.90     $     7.72
      Depletion ................................................................     $     4.09     $     4.06     $     3.86
</TABLE>

(a)      Gas production is converted to equivalent Bbls at the rate of 6 Mcf
         per Bbl, representing the estimated relative energy content of natural
         gas to oil.

OIL AND GAS RESERVES

         The estimates of the Company's proved oil and gas reserves, which are
located entirely within the United States, were prepared in accordance with the
guidelines established by the Security and Exchange Commission ("SEC") and
Financial Accounting Standards Board ("FASB"). The estimates as of December 31,
1998, 1997 and 1996 are based on evaluations prepared by independent petroleum
engineers. For information concerning costs incurred by the Company for oil and
gas operations, net revenues from oil and gas production, estimated future net
revenues attributable to the Company's oil reserves and present value of future
net revenues on a 10 percent discount rate and changes therein, see Notes to
the Company's Consolidated Financial Statements.



                                      16
<PAGE>   17

         There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Reservoir engineering is a subjective process of estimating subsurface
accumulations of oil and gas that cannot be measured in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of available
data and the interpretation thereof. As a result, estimates by different
engineers often vary, sometimes significantly. In addition, physical factors,
such as changes in product price, may justify revision of such estimates.
Accordingly, oil and gas quantities ultimately recovered will vary from reserve
estimates.

         Proved Reserves

         The estimated proved oil and gas reserves and present value of
estimated future net revenues from proved oil and gas reserves for the Company
as of December 31, 1998, 1997 and 1996, are summarized below:

<TABLE>
<CAPTION>
                                                                            For the Years Ended December 31,
                                               -------------------------------------------------------------------------------
                                                        1998                       1997                         1996
                                                        ----                       ----                         ----
                                                  Oil          Gas           Oil            Gas          Oil           Gas
                                                 (Bbls)       (Mcf)         (Bbls)         (Mcf)       (Bbls)         (Mcf)
                                              ----------     ----------    ---------     ----------    ---------     ---------
<S>                                            <C>           <C>           <C>            <C>          <C>           <C>      
Proved Reserves:
      Beginning of year ................       7,216,559     11,295,325    4,540,419      7,185,636    2,230,190     4,837,030
      Revisions of previous estimates...      (1,669,606)    (2,576,510)   1,304,819       (969,377)     548,009      (458,198)
      Extensions and discoveries .......         465,458      4,182,533    1,161,953                     205,859        28,442
      Purchase of minerals in place ....       5,118,101     20,024,034      762,282      6,206,929    1,838,595     3,339,214
      Sale of minerals in place ........        (142,316)       (28,925)    (148,902)      (343,565)     (46,455)     (126,680)
      Production .......................        (529,426)    (1,250,490)    (403,812)      (784,298)    (235,779)     (434,172)
                                              ----------     ----------    ---------     ----------    ---------     ---------
      End of year ......................      10,458,770     31,645,967    7,216,759     11,295,325    4,540,419     7,185,636
                                              ==========     ==========    =========     ==========    =========     =========
Proved Developed Reserves:
      Beginning of year ................       3,559,850      7,909,902    3,092,149      5,510,499    1,352,870     3,893,360
                                              ----------     ----------    ---------     ----------    ---------     ---------
         End of year ...................       6,708,844     22,613,532    3,559,850      7,909,902    3,092,149     5,510,499
                                              ==========     ==========    =========     ==========    =========     =========
</TABLE>



                                      17
<PAGE>   18


         Standardized Measure

         The following table sets forth the standardized measure of discounted
future net cash flows relating to proved reserves at December 31, 1998, 1997
and 1996:

<TABLE>
<CAPTION>
                                                                  For the Years Ended December 31,
                                                       ---------------------------------------------------
                                                           1998               1997               1996
                                                       -------------      -------------      -------------
<S>                                                    <C>                <C>                <C>          
Cash Flows Relating to Proved Reserves:
    Future cash flows ............................     $ 170,551,299      $ 131,921,276      $ 125,076,627
    Future costs:
       Production ................................       (69,536,325)       (45,194,356)       (47,139,363)
         Development .............................       (15,369,172)       (12,371,206)        (6,835,546)
         Income taxes ............................       (10,032,197)                --                 --
                                                       -------------      -------------      ------------- 
    Future net cash flows ........................        75,613,605         74,355,714         71,101,718
    10% discount factor ..........................       (25,376,691)       (35,775,170)       (30,250,175)
                                                       -------------      -------------      ------------- 

Standardized measure of discounted future net
   Cash flows ....................................     $  50,236,914      $  38,580,544      $  40,851,543
                                                       =============      =============      ============= 
</TABLE>


         Had the Company been a taxable entity at December 31, 1997, the future
income taxes would have been $14.1 million on an undiscounted basis and $7.8
million on a discounted basis, and the standardized measure of discounted
future net cash flows at December 31, 1997 would have been $37.0 million.

         The following table sets forth the changes in the standardized measure
of discounted future net cash flows relating to proved reserves for the years
ended December 31, 1998, 1997 and 1996, respectively:

<TABLE>
<CAPTION>
                                                                           For the Years Ended December 31,
                                                                 ------------------------------------------------
                                                                     1998              1997              1996
                                                                 ------------      ------------      ------------
<S>                                                              <C>               <C>               <C>         
Standardized Measure, Beginning of Year ....................     $ 38,580,544      $ 40,851,543      $ 17,242,730
     Net change in sales prices, net of production costs ...      (17,336,320)      (12,557,771)        6,601,987
     Development costs incurred during the year which
         were previously estimated .........................        3,000,000         5,073,000         2,033,000
     Revisions of quantity estimates .......................       (6,361,075)        6,325,872         4,182,057
     Extensions, discoveries and improved recovery, net
         of future production and development costs ........        4,296,455         2,382,351         1,485,041
     Accretion of discount .................................        3,858,054         4,085,154         1,724,273
     Change in future development costs ....................        4,484,697        (4,116,068)       (2,598,316)
     Change in timing and other ............................       (2,830,538)       (5,394,793)       (4,484,968)
     Purchases of reserves in place ........................       27,382,247         8,289,041        17,756,033
     Sales of reserves in place ............................         (498,478)       (1,171,519)          (97,141)
     Sales, net of production costs ........................       (4,338,672)       (5,186,266)       (2,993,153)
                                                                 ------------      ------------      ------------ 
Standardized Measure, End of Year ..........................     $ 50,236,914      $ 38,580,544      $ 40,851,543
                                                                 ============      ============      ============ 
</TABLE>



                                      18
<PAGE>   19

The preceding tables should be read in connection with the definitions of
proved reserves, proved developed reserves and proved undeveloped reserves set
out in Part I, Item 1, "Glossary of Oil and Gas Terms."

         Oil and Gas Prices

         In estimating oil reserves for 1998, 1997 and 1996, a price of $10.64,
$ 16.10 and $ 23.55 per barrel was used, which is the average actual price in
effect for the Company's oil production at the respective dates. In estimating
gas reserves for 1998, 1997 and 1996, a price of $1.83, $ 2.01 and $ 3.43 per
Mcf was used, based on prices in effect at the respective dates.

EXPLORATION AND PRODUCTION DATA

         For the following data, "gross" refers to the total wells or acres in
which the Company owns a working interest, and "net" refers to the gross wells
or acres multiplied by the percentage working interest owned by the Company.
Although many of the Company's wells produce both oil and gas, a well is
designated as an oil well or a gas well based upon the ratio of oil to gas
production.

         Producing Wells

         The following table summarizes the Company's producing wells as of
December 31, 1998, all of which are located in the United States:

<TABLE>
<CAPTION>
              Operated Wells        Non-operated Wells          Total                   
            -----------------       ------------------          -----
            Gross         Net        Gross       Net       Gross       Net
            -----         ---        -----       ---       -----       ---
<S>          <C>        <C>           <C>        <C>        <C>        <C>
Oil          504        467.1         75         16.9       579        484
Gas           43         38.2         22          2.8        65         41
             ---        -----        ---        -----       ---        ---
Total        547        505.3         97         19.7       644        525
             ===        =====        ===        =====       ===        ===
</TABLE>

         Drilling Activities

         The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 1998, 1997 and 1996. At
December 31, 1998, the Company was not in the process of drilling any wells.



                                      19
<PAGE>   20





<TABLE>
<CAPTION>
                                               For the Years Ended December 31,
                               ------------------------------------------------------------
                                      1998                   1997                1996
                                      ----                   ----                ----
                               Gross        Net       Gross       Net       Gross       Net
                               -----       ----       -----      ----       -----      ----
<S>                            <C>        <C>         <C>       <C>         <C>       <C>
Exploratory:
     Productive .........         2         .17         1         0.2         1         0.2
     Dry ................         0           0         4         0.5         1         0.1
                                 --        ----        --        ----        --        ----
        Total ...........         2         .17         5         0.7         2         0.3
                                 ==        ====        ==        ====        ==        ====
Developmental:
     Productive .........        11         9.8        18        17.5        15        10.5
     Dry ................         0           0         0         0.0         1         0.2
                                 --        ----        --        ----        --        ----
        Total ...........        11         9.8        18        17.5        16        10.7
                                 ==        ====        ==        ====        ==        ====
</TABLE>

         Acreage

         The following table sets forth information concerning the Company's
leasehold ownership interests as of December 31, 1998:

<TABLE>
<CAPTION>
                                            Gross          Net 
                                           ------          ---  
<S>                                        <C>           <C>   
Developed Acreage (a) .............        36,785        25,005
Undeveloped Acreage (b) ...........        48,520        29,444
                                           ------        ------

Total  Acreage ....................        85,305        54,449
                                           ======        ======
</TABLE>


(a)      "Developed acreage" is acreage spaced for or assignable to productive
         wells.

(b)      "Undeveloped acreage" is oil and gas acreage on which wells have not
         been drilled or to which no Proved Reserves other than Proved
         Undeveloped Reserves have been attributed.

EXECUTIVE OFFICERS OF VISTA

Set forth below is certain information concerning the executive officers of
Vista.

<TABLE>
<CAPTION>
Name                                Age                                Position
----                                ---                                --------
<S>                                 <C>              <C>                                              
C. Randall Hill                     40               Chairman of the Board, Chief Executive Officer
                                                              and Chief Financial Officer
Steven D. Gray                      39               President, Chief Operating Officer and Director
R. Cory Richards                    38               Executive Vice President--Exploration Manager
                                                                      and Secretary
</TABLE>



                                      20
<PAGE>   21

Set forth below is a description of the backgrounds of the executive officers
of Vista:

         C. Randall Hill serves as Chairman of the Board, Chief Executive
Officer and Chief Financial Officer of the Company. He formerly served as
Chairman of the Board and Chief Executive Officer of the Company's predecessors
since December, 1992. From 1985 until 1992, Mr. Hill practiced law with the law
firms of Weil, Gotshal & Manges and Johnson & Swanson in Dallas, Texas. Mr.
Hill earned his J.D. from the University of Tulsa in 1985 and his undergraduate
degree from the University of New Mexico in 1982.

         Steven D. Gray serves as President, Chief Operating Officer and a
director of the Company. He previously served in those positions with the
Company's predecessors since December, 1992. From 1982 until 1989, Mr. Gray
held several petroleum engineering positions with Texas Oil & Gas Corp. From
1989 to 1992, Mr. Gray was a petroleum operations and reservoir engineer with
Bettis, Boyle and Stovall, a privately held, independent oil and gas company in
Graham, Texas. Mr. Gray earned his B.S. degree in Petroleum Engineering from
Texas Tech University in 1982.

         R . Cory Richards serves as Executive Vice President and Exploration
Manager of the Company, as he did for its predecessor company since 1995. From
1987 until 1995, Mr. Richards was employed as Exploration Manager with J.
McShane, Inc., a privately held, independent oil and gas company in Monahans,
Texas. Mr. Richards earned his B.S. degree in Geological Sciences from the
University of Texas at Austin in 1985.

ITEM 3. LEGAL PROCEEDINGS

         At December 31, 1998, the Company was a Defendant in a lawsuit filed
on July 31, 1995, styled Manna Oil & Gas, Inc., Dobbs Oil & Gas, Inc. v.
Midland Resources, Inc. , Miresco Inc., Midland Resources Operating Company,
Inc., Cause No. 40,677. The case involved disputes with a non-operating
interest owner concerning the operation of certain Gulf Coast properties
located in Copano Bay, Aransas County, Texas, wherein the Company owns a 68
percent working interest and is the operator of the properties. The lawsuit was
settled in February 1999, whereby the Company acquired all of the interests of
the Plaintiff in the subject properties for a net purchase price of $0.7
million.

         From time to time, the Company and its subsidiaries are involved in
various other lawsuits and certain governmental proceedings arising in the
ordinary course of business. Company management and legal counsel do not
believe that the ultimate resolution of these claims will have a material
adverse effect on the Company's financial position or the results of its
operations.

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

         No matters were submitted to a vote of the Company's stockholders in
the fourth quarter of 1998.

                                    PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

         The Company's Common Stock and its Class B $4.00 Warrants ("Class B
Warrants") have been publicly traded on the American Stock Exchange ("AMEX")
since the consummation of the Merger on October 28, 1998, under the symbol
"VEI" and "VEI.WS." The high and low reported sales price for the Company's



                                      21
<PAGE>   22

Common Stock during the period from October 28, 1998 to December 31, 1998, was
$3.375 and $1.875, respectively. On March 15, 1999, the closing price of the
Common Stock was $1.50.

         As of December 31, 1998, the Company had 436 registered holders of its
Common Stock with 16,312,336 million shares outstanding. No dividends have been
declared or paid on the Company's Common Stock to date. The Company intends to
retain all future earnings for the development of its business.

ITEM 6. SELECTED FINANCIAL DATA

         The following table presents selected historical financial data of the
Company as of and for each of the years since the Company's or its predecessor
entities' inception on September 21, 1995. Future results may differ
substantially from historical results because of changes in oil and natural gas
prices, production declines and other factors. This information should be read
in conjunction with the Company's financial statements and notes thereto and
Management's Discussion and Analysis of Financial Condition and Results of
Operations presented elsewhere herein.

<TABLE>
<CAPTION>
                                                                                                                   
                                                                                                                  For the Period 
                                                                                                                  From Inception 
                                                                 As of or for the Year Ended December 31,         Sept. 21, 1995)
                                                          ------------------------------------------------------  to December 31,
                                                              1998                 1997                 1996           1995
                                                          ------------         ------------         ------------   ------------
<S>                                                       <C>                  <C>                  <C>            <C>         
REVENUES:
    Oil and gas sales                                     $  8,737,056         $  8,874,961         $  5,537,720   $  1,348,647
                                                          ------------         ------------         ------------   ------------
          Total revenues                                  $  8,737,056            8,874,961            5,537,720   $  1,348,647
                                                          ------------         ------------         ------------   ------------

COSTS AND EXPENSES:
    Lease operating                                          4,398,384            3,688,695            2,544,567        728,540
    Exploration costs                                           32,077               97,211              273,843             --
    Depreciation, depletion  & amortization                  3,014,707            2,169,098            1,272,316        308,132
    Impairment of oil and gas properties                    24,849,632                   --                   --             -- 
    General and administrative                               1,743,814              987,020              581,048        208,509
    Amortization of unit option awards                       4,262,089              315,518                   --             --
                                                          ------------         ------------         ------------   ------------
        Total costs and expenses                            38,300,703            7,257,542            4,671,774      1,245,181
                                                          ------------         ------------         ------------   ------------
         Operating income (loss)                           (29,563,647)           1,617,419              865,946        103,466
                                                          ------------         ------------         ------------   ------------
    Loss on sale of property                                  (317,293)             (86,678)             (56,738)            --
    Interest income                                              5,833                   --                   --             --
    Interest expense                                        (1,597,350)          (1,048,009)            (476,363)       (77,093)
    Other income (loss), net                                   111,745              115,949               61,437         33,684
                                                          ------------         ------------         ------------   ------------
NET INCOME (LOSS) BEFORE
    TAXES (1)                                              (31,360,712)             597,681              394,282         60,057
                                                          ------------         ------------         ------------   ------------
     Deferred federal income tax expense (benefit)          (6,560,351)             211,720              139,284         21,190
                                                          ------------         ------------         ------------   ------------
NET INCOME (LOSS)                                         $(24,800,361)        $    385,961         $    254,998   $     38,867
                                                          ============         ============         ============   ============
EARNINGS  (LOSS) PER SHARE                                $      (1.95)        $        .03         $        .02   $         --
                                                          ============         ============         ============   ============

CASH FLOW DATA:
EBITDAEX(2)                                                 (1,667,231)           3,883,728            2,412,105        411,598
Cash flows from operating activities                          (655,633)           3,469,638            2,072,649        195,878
Cash flows from investing activities                       (22,256,996)         (12,648,815)          (7,046,720)    (7,948,840)
Cash flows from financing activities                        22,385,500            9,189,095            5,015,077      8,265,167
Capital expenditures                                        22,805,360           13,038,815            7,417,091      7,720,478
Ratio of earnings to fixed charges (3)                              --                 1.6x                 1.8x           1.8x


BALANCE SHEET DATA (end of period):
Working capital                                               (427,266)             421,132              613,666        648,130
Property, plant, and equipment, net                         56,543,988           24,870,766           14,523,202      9,076,679
Total assets                                                59,743,317           27,036,103           16,259,340     10,364,620
Long-term debt                                              50,730,894           17,900,000            8,615,077      3,600,000
Stockholders' equity                                         5,368,695            7,696,652            6,783,453      6,389,171
</TABLE>



                                      22
<PAGE>   23

-------------------
(1)      The pro forma benefit (provision) for taxes is the amount that would
         have been recorded in the financial statements had the Company been a
         taxable entity during the relevant period. The Company became a
         taxable entity in connection with the Midland Merger on October 28,
         1998.

(2)      The Company believes that EBITDAEX may provide additional information
         about the Company's discretionary cash flow and its ability to meet
         its future requirements for debt service, capital expenditures and
         working capital. EBITDAEX is a financial measure commonly used in the
         oil and gas industry and should not be considered in isolation or as a
         substitute for net income, operating income, cash flows from operating
         activities or any other measures of financial performance presented in
         accordance with generally accepted accounting principles or as a
         measure of a company's profitability or liquidity. Because EBITDAEX
         excludes some, but not all, items that affect net income and these
         measures may vary among companies, the EBITDAEX data presented above
         may not be comparable to similarly titled measures of other companies.
         EBITDAEX (as used herein) is calculated by adding depletion,
         depreciation and amortization, impairment of oil and gas properties
         and exploration costs to operating income. Exploration costs represent
         discretionary cost items. Therefore, exploration costs have been added
         back in order to present a discretionary cash flow for the Company.

(3)      For purposes of calculating the ratio of earnings to fixed charges,
         earnings are defined as income (loss) before taxes plus fixed charges.
         Fixed charges consist of interest expense. For the year ended December
         31, 1998, earnings were insufficient to cover fixed charges by $29.8
         million.


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

         The following discussion and analysis should be read in conjunction
with Item 6, Selected Financial Data and the Company's Consolidated Financial
Statements.

GENERAL

         The following events affect the comparability of the results of
operations and financial condition of the Company for the years ended December
31, 1998, 1997 and 1996, and may impact future operations and financial
condition.

         The Formation of Vista

         Vista Energy Resources, Inc. ("Vista" or the "Company") is a Delaware
corporation whose common stock is listed and traded on the American Stock
Exchange. The Company was incorporated in May 1998 for the purpose of
consolidating and continuing the activities previously conducted by the Vista
Partnership and Midland Resources. The Company completed its merger with
Midland Resources on October 28, 1998.

         In accordance with the provisions of Accounting Principles Board
("APB") No. 16 Business Combinations, the merger of the Vista Partnership and
Midland Resources was accounted for as a purchase by the Company (formerly the
Vista Partnership). As a result, the historical financial statements for the
Company are those of the Vista Partnership.

         Acquisition Activities

         1998 Acquisitions - On October 28, 1998, the Midland Merger between
the Vista Partnership and Midland Resources was completed resulting in the
formation of the Company. As a result of the Midland Merger, Midland Resources'
security holders acquired 27.3 percent of the outstanding Common Stock of the
Company and security holders of the Vista Partnership acquired the remaining
72.7 percent of the outstanding Common Stock of the Company. In addition, upon
consummation of the Midland Merger, the Common Stock of

                                      23
<PAGE>   24


Vista, the newly merged company, became publicly traded on the
American Stock Exchange effective October 29, 1998.

         Effective as of October 1, 1998, the Company acquired working
interests ranging from 65 percent to 85 percent in a group of oil and gas
producing leases from IP Petroleum and certain of its working interest partners
(the "IP Acquisition"). These leases are located primarily in the War-Wink area
of Ward and Winkler Counties, Texas, and the interests were acquired for a
purchase price of $19.1 million. The IP Acquisition closed on December 18,
1998.

         1997 Acquisitions - In addition to acquiring various additional small
working interests and overriding royalty interests in properties already owned
and operated by the Company, the Company closed two significant producing
property acquisitions in 1997 (the "1997 Acquisitions"). In May 1997, but
effective September 1, 1996, the Company acquired all of the interests of
Coastal Oil and Gas Corporation in three producing leases located in the Howard
Glasscock Field, Howard County, Texas, for a net purchase price of $1.1
million. The interests acquired were attributable to leases in which the
Company already owned interests and were operated by the Company. Effective as
of July 1, 1997, the Company closed the acquisition pursuant to which the
Company acquired substantially all of the producing oil and gas properties from
E.G. for a net purchase price of $6.1 million (the "E.G. Acquisition").

         1996 Acquisitions - In addition to acquiring various additional small
working interests in oil and gas properties already owned and operated by the
Company, the Company closed two significant producing property acquisitions in
1996 (the "1996 Acquisitions"). Effective as of June 1, 1996, the Company
acquired a 100 percent working interest in two producing leases (14 wells)
located in the Sharon Ridge Field, Scurry County, Texas, for a net purchase
price of $0.5 million. Effective as of July 1, 1996, the Company acquired
producing oil and gas properties from Merit Energy Company and certain of its
partnership affiliates for a net purchase price of $4.1 million. All of the
Company's 1996 Acquisitions were funded through a combination of proceeds from
long-term borrowings and cash provided by operating activities.

         Drilling Results

         During the year ended December 31, 1998, the Company has continued its
emphasis on development, exploration and production activities, with a primary
focus on the exploitation of its current portfolio of drilling locations.
During 1998, the Company participated in the drilling and completion of 11
gross development wells and two gross exploration wells. Of the total wells
completed during 1998, 13 were completed successfully which resulted in a 100
percent success rate. The Company had no wells in progress at year end 1998.

         1999 Capital Budget

         The Company's 1999 capital expenditure drilling budget has been
approved at an amount up to $11.1 million. Pursuant to this budget, $9.3
million has been allocated to exploitation and development activities and $1.8
million to exploration activities. The Company does not budget for oil and gas
property acquisitions as they are made on a case by case basis as opportunities
arise. The 1999 budget reflects the Company's plans to drill and/or recomplete
approximately 25 oil and gas wells in 1999. The Company currently expects to
fund its



                                      24
<PAGE>   25

1999 capital expenditure budget primarily with internally generated cash flow,
borrowings under its bank credit facility and proceeds from the sale of
non-strategic assets.

         Sale of Properties

         During 1998, the Company sold certain oil and gas properties for a
total net consideration of $0.5 million, which resulted in a recognized loss of
$0.3 million. During 1997, the Company sold certain oil and gas properties for
a total net consideration of $0.4 million, which resulted in a recognized loss
of $0.1 million. During 1996, the Company sold certain oil and gas properties
for a total net consideration of $0.4 million, which resulted in a recognized
loss of $0.1 million.

         Oil and Gas Prices

         During 1998 and continuing into 1999, the oil and gas industry has
operated in a severely depressed commodity price environment. Oil prices during
the first quarter of 1999 fell to their lowest levels in history when adjusted
for inflation. Although oil prices improved to some degree in late March 1999,
current prices remain substantially lower than levels achieved in 1997.

RESULTS OF OPERATIONS

         Comparison of 1998 Results to 1997

         The Company reported a net loss of $24.8 million for 1998, as compared
to net income of $0.4 million for the year ended at December 31, 1997. As
discussed more fully below, the Company's financial performance for the year
ended December 31, 1998 was negatively impacted by the following items: (i)
significant reduction in the prices received for oil and gas sales of 31 percent
and 19 percent, respectively, from 1997 levels; (ii) significant impairment of
its oil and gas properties, resulting from historically low oil and gas prices
at year end, together with the effects of purchase accounting rules applied to
the Midland Merger which required the Company to book the Midland Resources' oil
and gas assets at $37.0 million then subsequently write down such assets to
$14.8 million at year end; (iii) the costs and expenses of the Midland Merger
and compensation expense associated with the termination of the Vista
Partnership option plan; (iv) increase in gross production costs due to the
addition of properties acquired in 1997 and 1998 from E. G., Midland Resources
and IP Petroleum; and (v) an increase in interest expense as a result of the
additional indebtedness incurred in respect of the E.G. Acquisition, the Midland
Merger and the IP Acquisition.

         Net cash used in operating activities was $0.7 million for the year
ended December 31, 1998, as compared to net cash provided by operating
activities of $3.5 million for the same period in 1997. This decrease was
primarily attributable to significantly lower commodity prices for oil and gas
and increased production costs and interest expense as a result of the
additional properties acquired and indebtedness incurred in respect of the E.G.
Acquisition, the Midland Merger and the IP Acquisition.



                                      25
<PAGE>   26

         For the year ended December 31, 1998, the Company's oil and gas
revenues (including the effects of hedging activities) decreased to $8.7
million from $8.9 million in 1997, representing a decrease of 2 percent from
the prior year. Such decrease was attributable to the significant reduction in
oil and gas prices received offset by increases in production of both oil and
gas.

         During 1998, the Company produced 529 MBbls of oil and 1,250 MMcf of
gas (738 MBOE), representing increases of 31 percent and 59 percent,
respectively, over 1997. The production increases resulted primarily from the
1998 Acquisitions, as well as the Company's successful drilling and
exploitation activities. The average daily production of oil and gas was 1,450
BOPD and 3,426 Mcfd, representing increases of 31 percent and 59 percent,
respectively, over 1997.

         Average oil prices decreased significantly from $17.63 per barrel in
1997 to $12.25 per barrel in 1998. Average natural gas prices decreased from
$2.22 per Mcf in 1997 to $1.80 per Mcf in 1998. The average oil price includes
hedging gains in 1998 of $0.8 million or $1.64 per barrel. The average natural
gas price includes hedging gains in 1998 of $0.1 million or $0.07 per Mcf.

         Oil and gas production costs, including production and ad valorem
taxes, increased to $4.4 million ($5.96 per BOE) for the year ended December
31, 1998, compared to $3.7 million ($6.90 per BOE) in 1997. The increase in oil
and gas production costs was primarily attributable to the properties acquired
in the 1998 Acquisitions and having a full year of production costs related to
the 1997 Acquisitions.

         Exploration and abandonment costs decreased from $0.1 million in 1997
to $32,077 in 1998, resulting from the Company's drilling of no dry holes in
1998, and a decreased write-down of expired acreage.

         General and administrative expenses, net of third party
reimbursements, for 1998 totaled $1.7 million ($2.36 per BOE), a 77 percent
increase from 1997. The increase resulted primarily from the 1998 Acquisitions,
which resulted in the hiring of additional personnel to handle the Company's
expanded operations.

         Depletion, depreciation and amortization expense for 1998 totaled $3.0
million ($4.09 per BOE), an increase of $0.8 million or 39 percent from 1997.
This increase relates to a full year of depletion relating to production
attributable to the 1997 Acquisitions and depletion relating to production
attributable to the 1998 Acquisitions.

         Impairment of oil and gas properties for 1998 totaled $24.8 million.
The impairment was the result of applying Statement of Financial Accounting
Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of." In applying this
statement, the Company determined that the estimated future net cash flows
(undiscounted and without interest charges) expected to result from the use of
these assets was less than the carrying amount (book value) of these assets
and, accordingly, recorded an impairment based on the fair value of the assets.
In 1998, the impairment primarily resulted from substantially lower oil and
natural gas prices at year end coupled with the effects of applying the
purchase accounting method to the properties acquired in the Midland Merger.
Under purchase accounting rules, the Company recorded the oil and gas assets
acquired in the Midland Merger at the purchase price of $37.0 million, then
subsequently recognized an impairment on those assets of $22.2 million at
December 31, 1998 due to the significant drop in oil and gas prices from May
1998, when the Midland Merger was



                                      26
<PAGE>   27

announced, until December 1998. Accordingly, the impairment associated with the
properties acquired in the Midland Merger accounted for 90 percent of the total
impairment recognized by the Company in 1998. The Company recognized no
impairment in 1997.

         Interest expense was $1.6 million in 1998, compared to $1.0 million in
1997, an increase of 52 percent. Interest expense was primarily attributable to
increased debt levels relating to the financing of the 1997 and 1998
Acquisitions.

         Comparison of 1997 Results to 1996

         For the year ended December 31, 1997, the Company's oil and gas
revenues (including the effects of hedging activities) increased to $8.9
million from $5.5 million in 1996, representing an increase of 62 percent from
the prior year. The revenue increase was due to additional production from the
1997 Acquisitions, as well as the Company's successful drilling and
exploitation activities.

         During 1997, the Company produced 404 MBbls and 784 MMcf of gas (535
MBOE), representing increases of 59 percent and 71 percent, respectively, over
1996. The production increases resulted primarily from the 1997 Acquisitions,
as well as the Company's successful drilling and exploitation activities. The
average daily production of oil and gas was 1,107 BOPD and 2,148 Mcfd,
representing increases of 60 percent and 71 percent, respectively, over 1996.

         Average oil prices decreased from $18.04 per barrel in 1996 to $17.63
per barrel in 1997. Average natural gas prices increased slightly from $2.19
per Mcf in 1996 to $2.22 per Mcf in 1997. The average oil price includes
hedging losses in 1997 of $0.2 million or $.50 per barrel. No natural gas price
hedges were in place in 1996.

         Oil and gas production costs, including production and ad valorem
taxes, increased to $3.7 million ($6.90 per BOE) for the year ended December
31, 1997, compared to $2.5 million ($7.72 per BOE) in 1996. The increase in oil
and gas production costs was primarily attributable to the properties acquired
in the 1997 Acquisitions.

         Exploration and abandonment costs decreased from $0.3 million in 1996,
to $0.1 million in 1997. Such reduced costs were the result of less dry hole
costs and a decreased write-down of expired acreage.

         General and administrative expenses, net of third party
reimbursements, for 1997 totaled $1.0 million ($1.85 per BOE), a 70 percent
increase from 1996. The increase resulted primarily because of the 1997
Acquisitions, which resulted in the hiring of additional personnel to handle
the Company's expanded operations.

         Depletion, depreciation and amortization expense for 1997 totaled $2.2
million ($4.06 per BOE), an increase of $0.9 million or 69 percent from 1996.
This increase relates to a full year of depletion relating to production for
the 1996 Acquisitions and depletion related to the 1997 Acquisitions.

         The Company recognized no impairment charges for either 1997 or 1996.



                                      27
<PAGE>   28

         Interest expense was $1.0 million in 1997, compared to $0.5 million in
1996, an increase of 100 percent. The increase in interest expense was
primarily attributable to increased debt levels relating to the financing of
the 1997 Acquisitions.

LIQUIDITY AND CAPITAL RESOURCES

         The Company's primary sources of liquidity are cash flow from
operations, borrowings under its bank credit facility, and proceeds from the
sale of non-strategic assets.

         Net cash used in operating activities was $0.7 million for the year
ended December 31, 1998, as compared to net cash provided by operating
activities of $3.5 million and $2.1 million for the same periods in 1997 and
1996, respectively. This decrease in 1998 was primarily attributable to
significantly lower commodity prices for oil and gas and increased production
costs and interest expense as a result of the additional properties acquired
and indebtedness incurred related to the E.G. Acquisition, the Midland Merger
and the IP Acquisition. Net cash provided by operating activities increased 67
percent to $3.5 million for the year ended December 31, 1997, as compared to
$2.1 million for the year ended December 31, 1996. This increase was primarily
attributable to (i) significantly increased oil and gas revenue attributable to
increased production resulting from the success of the Company's drilling
program and the addition of a significant group of properties acquired in the
E.G. Acquisition in the third quarter of 1997; and (ii) a decrease in
exploration expenses due to fewer write offs of expired acreage and less dry
hole expenses.

         The Company's cash requirements are generally for acquisitions,
development and exploration of oil and gas properties, repayment of principal
and interest on outstanding indebtedness and working capital obligations. The
Company's cash expenditures for the year ended December 31, 1998, 1997 and
1996, for additions to oil and gas properties totaled $22.8 million, $13.0
million and $7.4 million, respectively.

         The Company's 1999 capital expenditure drilling budget has been
approved at an amount up to $11.1 million. Pursuant to this budget, $9.3
million has been allocated to exploitation and development activities and $1.8
to exploration activities. The Company does not budget for oil and gas property
acquisitions as they are made on a case by case basis as opportunities arise.
The 1999 budget reflects the Company's plans to drill and/or recomplete
approximately 25 oil and gas wells in 1999. The Company currently expects to
fund its 1999 capital expenditure budget primarily with internally generated
cash flow, borrowings under its bank credit facility and proceeds from the sale
of non-strategic assets.

         Financing Activities

         The Company had $49.9 million outstanding under its Credit Facility at
December 31, 1998. The weighted average interest rate for the year ended
December 31, 1998 on the Company's indebtedness was 7.68 percent as compared to
7.76 percent for the year ended December 31, 1997, and 7.99 percent for the
year ended December 31, 1996 (taking into account the effect of any interest
rate swaps). On December 18, 1998, the Company entered into the Credit Facility
with BankBoston, N.A., as agent, which has a current borrowing base of $55
million and an additional $5.0 million letter of credit facility. The borrowing
base under the Credit Facility is adjusted semi-annually with the next
borrowing base redetermination scheduled for August 31, 1999. The Company had
$5.1 million of unused borrowing capacity under its Credit Facility at December
31, 1998.



                                      28
<PAGE>   29

The Company has two options with respect to interest rate elections on
borrowings under the Credit Facility. The Company may either elect an interest
rate equal to the prime rate plus the applicable margin or the London Interbank
Offered Rate (" LIBOR Rate") plus the applicable margin. The applicable margin
will be adjusted for borrowing base usage and ranges from 150 basis points to
250 basis points. The LIBOR-based option provides for one-,three-,six-or
twelve- month periods. The Company's effective interest rate under the Credit
Facility was 7.5 percent as of December 31, 1998.

         The Credit Facility contains two financial covenants including a
minimum current ratio, including available borrowing capacity, of 1:1 and an
interest coverage to EBITDA test (2.0 to 1.0 for the four-fiscal quarter period
ending December 31, 1998; 2.25 to 1.0 for the four-fiscal quarter period ending
March 31, 1999; and 2.5 to 1.0 for each four-fiscal quarter period thereafter).
The Credit Facility also includes covenants which, among other things, restrict
the incurrence of additional indebtedness and the sale or acquisition of oil
and gas properties above certain levels without the consent of the lender.

         Hedging Activities

         The oil and gas prices that the Company reports are based on the
actual prices received for the commodities adjusted for the results of any of
the Company's hedging activities. The Company periodically enters into
commodity derivative contracts (i.e., swaps and collars) in order to (i) reduce
the effect of the volatility of price changes on the commodities the Company
produces and sells; (ii) support the Company's annual capital budgeting and
expenditure plans; and (iii) lock in prices to protect the economics related to
certain capital projects.

         The Company also hedges from time to time the basis for its natural
gas production which depends upon the location of its gas production. Such
basis hedges are immaterial to the financial performance of the Company.

         Amortization of Unit Option Awards

         The amortization of unit option awards was $4.3 million and $0.3
million for the year ended December 31, 1998 and 1997, respectively. The Company
did not provide for amortization of the unit option awards in 1996 as such
amounts were not material. The Company estimated the compensation associated
with the option awards based on estimated fair value less exercise price.
Estimated compensation expense was recorded over the vesting period and was
adjusted prospectively as the estimated fair value of the options changed.
However, prior to the closing of the Midland Merger, the subject options were
exercised by the holders thereof, exchanged for Common Stock of the Company as a
part of the Midland Merger and the option plan pursuant to which they were
granted was terminated. Accordingly, the unit option awards were fully vested as
of October 28, 1998, and all remaining compensation expense relating to the unit
option awards was recognized at that time based on the estimated current fair
value.

YEAR 2000 READINESS DISCLOSURE

         "Year 2000," or the ability of computer systems to process dates with
years beyond 1999, affects almost all companies and organizations. Computer
systems that are not Year 2000 compliant by January 1, 2000 may



                                      29
<PAGE>   30

cause material adverse effects to companies and organizations that rely upon
those systems. Continuity of the Company's operations in January 2000 will not
only depend upon Year 2000 compliance of the Company's computer systems and
computer-controlled equipment, but also compliance of computer systems and
computer-controlled equipment of third parties. These third parties include oil
and natural gas purchasers and significant service providers such as electric
utility companies and natural gas plant, pipeline and gathering system
operators.

         The Company is in the process of reviewing its computer systems and
computer-controlled field equipment and making the necessary modifications for
Year 2000 compliance. The Company has completed modifications and testing of
its primary accounting and land computer programs. The remaining computer
systems have been inventoried and assessed. Remediation and testing of
significant remaining systems are expected to be complete by August 1999.

         Based on its review, remediation efforts and the results of testing to
date, the Company does not believe that timely modification of its computer
systems and computer-controlled equipment for Year 2000 compliance represents a
material risk to the Company. The Company estimates that total costs related to
Year 2000 compliance efforts will be less than $10,000, of which approximately
$3,600 has been incurred and expensed through December 1998.

         Despite efforts to assure that such third parties are Year 2000
compliant, the Company cannot provide assurance that all significant third
parties will achieve compliance in a timely manner. A third party's failure to
achieve Year 2000 compliance could have a material adverse effect on the
Company's operations and cash flow. The potential effect of Year 2000
non-compliance by third parties is currently unknown.

         The Company will develop appropriate contingency plans in the event it
becomes aware of potential problems resulting from failure of the Company's or
of significant third party computer systems on January 1, 2000. The Company has
not developed any contingency plans to date. Specific contingency plans will be
developed in response to the results of testing scheduled to be complete by May
31, 1999, as well as the assessed probability and risk of system or equipment
failure. These contingency plans may include installing backup computer systems
or equipment, temporarily replacing systems or equipment with manual processes,
and identifying alternative suppliers, service companies and purchasers. The
Company expects these plans to be complete by July 31, 1999.

         The failure to correct a material Year 2000 problem could result in an
interruption in, or failure of, certain normal business activities or
operations. Due to the general uncertainty inherent in the Year 2000 problem,
resulting in part from the inability to ensure readiness of third parties, the
Year 2000 compliance issue could have a material adverse impact on the
Company's results of operations and financial condition.

FORWARD LOOKING STATEMENTS

          Certain information included in this year-end report on Form 10-K and
other materials filed by the Company with the SEC contain forward-looking
statements that involve risks and uncertainties that could cause actual results
to differ from projected results. Such statements address activities, events or
developments that the Company expects, believes, projects, intends or
anticipates will or may occur, including such matters as 



                                      30
<PAGE>   31

future capital, development and exploration expenditures (including the amount
and nature thereof), drilling of wells, reserve estimates (including estimates
of future net revenues associated with such reserves and the present value of
such future net revenues), future production of oil and natural gas, future
sales prices for oil and gas production, business strategies, expansion and
acquisition, obtaining financial or industry partners for prospect or program
development, or marketing of oil and natural gas. Factors that could cause
actual results to differ materially are described, among other places, in the
Marketing, Competition, Environmental Matters and Governmental Regulation
sections in this 10-K and under the caption "Management's Discussion and
Analysis of Financial Condition and Results of Operations." Without limiting
the Cautionary Disclosures so described, Cautionary Disclosures include, among
others: general economic conditions, the market price of oil and natural gas,
the risks associated with exploration, the Company's ability to find, acquire,
market, develop and produce new properties, operating hazards inherent to the
oil and natural gas business, uncertainties in the estimation of proved
reserves and in the projection of future rates of production and timing of
development expenditures, the strength and financial resources of the Company's
competitors, the Company's ability to find and retain skilled personnel,
climatic conditions, labor relations, availability and cost of material and
equipment, environmental risks, the results of financing efforts, and
regulatory developments. All written and oral forward-looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Disclosures. The Company
disclaims any obligation to update or revise any forward-looking statement to
reflect events or circumstances occurring hereafter or to reflect the
occurrence of anticipated or unanticipated events.

NEW ACCOUNTING STANDARDS

         In June 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") 130, "Reporting
Comprehensive Income," which establishes standards for reporting and displaying
comprehensive income and its components in a full set of general purpose
financial statements. SFAS 130 requires that all items that are to be
recognized under accounting standards as components of comprehensive income
(revenue, expenses, gains and losses) be reported in a financial statement that
is displayed with the same prominence as other financial statements. For the
years ended December 1998, 1997 and 1996, the Company reported no differences
between comprehensive income and net income.

         In June 1997, the Financial Accounting Standards Board issued SFAS
131, "Disclosures about Segments of an Enterprise and Related Information,"
which requires reporting of financial and descriptive information about a
company's reportable operating segments. The Company has identified only one
operating segment, which is the exploration and production of oil and gas.

         The Company will be required to comply with the provisions of SFAS
133, "Accounting for Derivative Instruments and Hedging Activities," which must
be adopted for fiscal years beginning after June 15, 1999. SFAS 133 requires
that derivatives be reported on the balance sheet at fair value and, if the
derivative is not designated as a hedging instrument, changes in fair value
must be recognized in earnings in the period of change. If the derivative is
designated as a hedge, and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability (if applicable) or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in earnings when the offsetting hedged transaction occurs. The definition of
derivatives has also been expanded to include contracts that require physical
delivery of oil and gas if the contract allows for net cash settlement.



                                      31
<PAGE>   32

The Company primarily uses derivatives to hedge product price and interest rate
risks. These derivatives are recorded at cost, and gains and losses on such
derivatives are reported when the hedged transaction occurs. Accordingly,
adoption of SFAS 133 will have an impact on the reported financial position of
the Company, and although such impact has not been determined, it is currently
not believed to be material. Adoption of SFAS 133 should have no significant
impact on reported earnings, but could materially affect comprehensive income.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

         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.

         The Company's business is impacted by fluctuations in commodity prices
and interest rates. The following discussion is intended to identify the nature
of these market risks, describe the Company's strategy for managing such risks
and to quantify the potential affect of market volatility on the Company's
financial condition and results of operations.

OIL AND GAS PRICES

         The Company's financial condition, results of operations and capital
resources are highly dependent upon the prevailing market prices of, and demand
for, oil and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are
beyond the control of the Company. These factors include the level of global
demand for petroleum products, foreign supply of oil and gas, the establishment
of and compliance with production quotas by oil-exporting countries, weather
conditions, the price and availability of alternative fuels and overall
economic conditions, both foreign and domestic. It is impossible to predict
future oil and gas prices with any degree of certainty. Sustained weakness in
oil and gas prices may adversely affect the Company's financial condition and
results of operations, and may also reduce the amount of net oil and gas
reserves that the Company can produce economically. Any reduction in reserves,
including reductions due to price fluctuations, can have an adverse affect on
the Company's ability to obtain capital for its exploration and development
activities. Similarly, any improvements in oil and gas prices can have a
favorable impact on the Company's financial condition, results of operations
and capital resources. Based on the Company's estimated 1999 levels of oil and
gas production, a $1 change in the price per Bbl of oil and a $.10 change in
the price per Mcf of gas would result in an aggregate change in gross revenues
of approximately $1.4 million.

         From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure to
price fluctuations. While the use of these hedging arrangements limits the
downside risk of price declines, such use may also limit any benefits which may
be derived from price increases. The Company uses various financial
instruments, such as swaps and collars, whereby monthly settlements are based
on differences between the prices specified in the instruments and the
settlement prices of certain futures contracts quoted on the NYMEX or certain
other indices. Generally, when the applicable settlement price is less than the
price specified in the contract, the Company receives a settlement from the
counterparty based on the difference. Similarly, when the applicable settlement
price is higher than the specified price, the Company pays the counterparty
based on the difference. The instruments utilized by the



                                      32
<PAGE>   33

Company differ from futures contracts in that there is not a contractual
obligation which requires or permits the future physical delivery of the hedged
products.

         During 1998 and continuing into 1999, the oil and gas industry has
operated in a depressed commodity price environment. Oil prices during the
first quarter of 1999 fell to their lowest levels in history when adjusted for
inflation. Although oil prices improved to some degree in late March 1999,
current prices remain substantially lower than levels achieved in 1997. In
1997, the Company entered into swap arrangements on a significant portion of
its 1998 oil production and realized a gain of $0.8 million in 1998 on oil
hedges. In addition, the Company hedged a portion of its 1998 gas production at
various times beginning in April 1998 and realized net gains of $0.1 million in
1998 on gas hedges.

         Set forth below is the contract amount and material terms of all crude
oil hedging instruments held by the Company at December 31, 1998 (monthly
volumes are expressed in Bbls and all prices are expressed in the calendar
monthly average of daily NYMEX closing prices for Light Sweet Crude Oil):

<TABLE>
<CAPTION>
      TRADE DATE           TYPE TRANSACTION       MONTHLY VOLUME     PUT FLOOR PRICE      CALL CEILING PRICE           TERM
      ----------           ----------------       --------------     ---------------      ------------------           ----
     <S>                  <C>                     <C>                <C>                  <C>                   <C>               
       12-15-97                 Collar                10,000            $18.50 Bbl            $19.28 Bbl         4-1-98 to 3-31-99
       12-11-98                  Swap                 40,000            $14.20 Bbl            $14.20 Bbl         8-1-99 to 6-30-00
</TABLE>

         Set forth below is the contract amount and material terms of all NYMEX
natural gas hedging instruments held by the Company at December 31, 1998
(monthly volumes are expressed in MMBtus and prices are expressed in the
monthly NYMEX (Henry Hub) closing price for natural gas):

<TABLE>
<CAPTION>
      TRADE DATE        TYPE TRANSACTION       MONTHLY VOLUME        PUT FLOOR PRICE      CALL CEILING PRICE           TERM
      ----------        ----------------       --------------        ---------------      ------------------           ----
     <S>                <C>                    <C>                   <C>                  <C>                   <C>              
        8-20-98              Collar                40,000               $2.25 Mcf             $2.45 Mcf         1-1-99 to 12-31-99
       11-12-98              Collar                50,000               $2.25 Mcf             $2.51 Mcf         1-1-99 to 12-31-99
        8-20-98              Collar                40,000               $2.17 Mcf             $2.34 Mcf         1-1-99 to 12-31-99
       12-28-98               Swap                 50,000               $2.01 Mcf             $2.01 Mcf         1-1-99 to 12-31-99
</TABLE>

         The Company also hedges from time to time the basis for its natural
gas production which depends upon the location of its gas production. Such
basis hedges are immaterial to the financial performance of the Company. As of
December 31, 1998, the Company had hedged approximately 21 percent of estimated
1999 oil production and 68 percent of estimated 1999 natural gas production. As
of December 31, 1998, the Company had hedged 19 percent of estimated 2000 oil
production. Subsequent to December 31, 1998, the Company has hedged an
additional 22 percent of 1999 estimated oil production. Subsequent to December
31, 1998, the Company has hedged 42 percent of 2000 estimated natural gas
production and 44 percent of 2001 natural gas production.

INTEREST RATES

         All of the Company's outstanding indebtedness at December 31, 1998 is
subject to market rates of interest as determined from time to time by the
banks pursuant to the Credit Facility. See "Liquidity and Capital Resources."
Any increases in the variable interest rates related to these facilities can
have an adverse impact on the Company's results of operations and cash flow. In
an attempt to manage these risks, the Company entered into an interest rate
swap effective December 23, 1997, which is accounted for as a hedge with any
realized gains or losses appropriately recorded as interest expense. The swap
consists of $10 million 



                                      33
<PAGE>   34

notional amount of indebtedness at a fixed swap rate of 6.02 percent based on
the 3-month LIBOR for the Company. The term of this swap ends on December 31,
1999. Based on the Company's outstanding indebtedness under its bank facility
at December 31, 1998 of $49.9 million, a change in interest rates of 25 basis
points would affect annual interest payments by approximately $0.1 million.

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 included elsewhere
in this Form 10-K.

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

         None.

                                   PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         The information required by this item is incorporated by reference to
information under the caption "Proposal 1 -- Election of Directors" and to the
information under the caption "Compliance with Section 16(a) of the Securities
Exchange Act of 1934" in the Company's definitive Proxy Statement (the "1999
Proxy Statement") for its annual meeting of stockholders to be held on or about
May 24, 1999. The 1999 Proxy Statement will be filed with the Securities
Exchange Commission (the "Commission') not later than 120 days subsequent to
December 31, 1998.

         Pursuant to Instruction 3 to Item 401(b) of Regulation S-K, the
information required by this item with respect to executive officers of the
Company is set forth in Part I of this report.

ITEM 11. EXECUTIVE COMPENSATION

         The information required by this item is incorporated herein by
reference to the 1999 Proxy Statement, which will be filed with the Commission
not later than 120 days subsequent to December 31, 1998.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         The information required by this item is incorporated herein by
reference to the 1999 Proxy Statement, which will be filed with the Commission
not later than 120 days subsequent to December 31, 1998.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The information required by this item is incorporated herein by
reference to the 1999 Proxy Statement, which will be filed with the Commission
not later than 120 days subsequent to December 31, 1998.



                                      34
<PAGE>   35

                                    PART IV.

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

(a)      Exhibits

         *2.1     Agreement and Plan of Merger, dated as of May 22, 1998, among
                  Vista Resources Partners, L.P., Midland Resources, Inc.,
                  Vista Energy Resources, Inc. and Midland Merger Co.

         *2.2     Form of Midland Exchange Agreement by and among Vista Energy
                  Resources, Inc. and certain securityholders of Midland
                  Resources, Inc.

         *2.3     Form of Vista Exchange Agreement by and among Vista Energy
                  Resources, Inc. and securityholders of Vista Resources I,
                  Inc. and Vista Resources Partners, L.P.

         *3.1     Certificate of Incorporation of Vista Energy Resources, Inc.

         *3.2     Bylaws of Vista Energy Resources, Inc.

         **4.1    Specimen Stock Certificate for the Common Stock, par value
                  $.01 per share of Vista Energy Resources, Inc.

         *4.2     Form of Registrations Rights Agreement by and among Vista
                  Energy Resources, Inc. and certain securityholders of Vista
                  Resources I, Inc. and Vista Resources Partners, L.P.

         *4.3     Form of Registration Rights Agreement by and among Vista
                  Energy Resources, Inc. and certain securityholders of Midland
                  Resources, Inc.

         *4.4     Form of Vista Warrant of Vista Energy Resources, Inc.

         *10.1    Contract Operating Agreement, effective as of June 1, 1998,
                  by and between Vista Resources, Inc. and Midland Resources
                  Operating Company, Inc.

         *10.2    Warley Settlement Agreement, dated May 22, 1998, between
                  Midland Resources, Inc. and Deas H. Warley III.

         *10.3    Release and Hold Harmless Agreement, dated May 22, 1998
                  between Marilyn D. Wade, Deas H. Warley III and Midland
                  Resources, Inc.

         *10.4    Form of Advisory Services Agreement between Vista Energy
                  Resources, Inc., Natural Gas Partners II, L.P. and Natural
                  Gas Partners III, L.P.

         *10.5    Vista Energy Resources, Inc. 1998 Employee Stock Option Plan.



                                      35
<PAGE>   36

         *10.6    Form of Midland Option Exercise Agreement.

         *10.7    Form of Indemnification Agreement by and between Vista Energy
                  Resources, Inc. and each of its directors and executive
                  officers.

         *10.8    Form of Indemnification Agreement by and between Vista Energy
                  Resources, Inc. and each of the directors and executive
                  officers of Midland Resources, Inc.

         *10.9    Termination Agreement, dated May 22, 1998, by and among Vista
                  Energy Resources, Inc., Midland Resources, Inc. and Howard E.
                  Ehler.

         *10.10   Termination Agreement, dated May 22, 1998, by and among Vista
                  Energy Resources, Inc., Midland Resources, Inc. and Marilyn
                  D. Wade.

         *10.11   Office Lease, dated October 10, 1996 between Vista Resources,
                  Inc. and Fasken Center, Ltd.

         *10.12   Lease Amendment, dated September 18, 1997 between Vista
                  Resources, Inc. and Fasken Center, Ltd.

          10.13   Credit Agreement, dated December 18, 1998 by and between
                  Vista Resources Partners, L.P. and Midland Resources, Inc.,
                  as borrowers, Vista Energy Resources, Inc., as guarantor,
                  BancBoston Robertson Stephens Inc., as arranger and
                  syndication agent, BancBoston, N.A., as administrative agent
                  and certain financial institutions.

          21.1    Subsidiaries of Vista Energy Resources, Inc.

          23.1    Independent Auditors Consent.
 
          27.1    Financial Data Schedule


         *Incorporated by reference to the Company's Registration Statement on
Form S-4 (File No. 33-58495) filed on July 2, 1998.

         **Incorporated by reference to the Amendment No. 1 to the Company's
Registration Statement on Form S-4 (File No. 33-58495) filed on August 25,
1998.

(b) Reports on Form 8-K

         The Company filed a Current Report on Form 8-K dated October 28, 1998
regarding consummation of the Merger with Midland Resources, Inc.


                                      36
<PAGE>   37


         The Company filed a Current Report on Form 8-K dated December 22, 1998
regarding its acquisition of a group of producing oil and gas properties from
IP Petroleum Company.

         The Company filed a Current Report on Form 8-K/A dated March 3, 1999
regarding its acquisition of a group of producing oil and gas properties from
IP Petroleum Company.

ITEM 15. OTHER INFORMATION

         Pursuant to Rule 14a-4(c)(1) of the Securities Exchange Act of 1934,
the Company's management will have discretionary authority with respect to
proxies submitted to the 1999 annual meeting of stockholders on any matter
which the Company does not receive notice of within 45 days after the first
public notice of such meeting is sent to the stockholders of the Company. This
rule does not affect the deadline set forth in Rule 14a-8 of the Securities
Exchange Act of 1934 for including a stockholder proposal in the Board of
Directors' solicitation of proxies. A stockholder proposal must be received by
R. Cory Richards, Secretary of the Company, in a reasonable time before the
Company begins to print and mail its proxy materials in order to be included in
such proxy materials.



                                      37
<PAGE>   38


                                   SIGNATURES

         Pursuant to the requirements 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.


<TABLE>
<S>                                <C>                                               <C> 
/s/ C. Randall Hill
----------------------             Chairman of the Board, Chief Executive              March 30, 1999
C. Randall Hill                    Officer, and Chief Financial Officer
                                   (Principal Accounting Officer and
                                   Duly Authorized Officer)

/s/ Steven D. Gray
----------------------             Director, President, and Chief Operating            March 30, 1999
Steven D. Gray                     Officer

/s/ Kenneth A. Hersh
----------------------             Director                                            March 30, 1999
Kenneth A. Hersh

/s/ David R. Albin
----------------------             Director                                            March 30, 1999
David R. Albin

/s/ John S. Foster
----------------------             Director                                            March 30, 1999
John S. Foster

/s/ John Q. Adams
----------------------             Director                                            March 30, 1999
John Q. Adams
</TABLE>



                                      38
<PAGE>   39


                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                                                                                          PAGE
                                                                                                          ----
          <S>                                                                                             <C>
         Report of Independent Public Accountants ........................................................F-2

         Consolidated Balance Sheets as of December 31, 1997 and 1998 ....................................F-3

         Consolidated Statements of Operations for the years ended
                  December 31, 1996, 1997 and 1998 .......................................................F-4

         Consolidated Statements of Changes in Owners' Equity
                  For the years ended December 31, 1996, 1997 and 1998....................................F-5

         Consolidated Statements of Cash Flows for the years ended December 31,
                  1996, 1997 and 1998 ....................................................................F-6

         Notes to Consolidated Financial Statements ......................................................F-7
</TABLE>



                                      F-1
<PAGE>   40



                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Board of Directors of Vista Energy Resources, Inc.:

         We have audited the accompanying consolidated balance sheets of Vista
Energy Resources, Inc. (a Delaware corporation) as of December 31, 1998 and
1997, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

         We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

         In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Vista Energy
Resources, Inc. as of December 31, 1998 and 1997, and the results of its
operations and cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.



                                                   ARTHUR ANDERSEN LLP


Dallas, Texas
March 29, 1999



                                      F-2
<PAGE>   41



                          VISTA ENERGY RESOURCES, INC.
                          CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                                                            DECEMBER 31,
                                                                                 ------------------------------
                                                                                     1998              1997
                                                                                 ------------      ------------
<S>                                                                              <C>               <C>
CURRENT ASSETS:
  Cash and cash equivalents                                                      $         --      $    527,129
  Accounts receivable:
     Oil and gas sales                                                              1,498,727         1,113,302
     Trade                                                                            900,401           136,633
  Other                                                                               262,218            83,519
                                                                                 ------------      ------------
         Total Current Assets                                                       2,661,346         1,860,583

PROPERTY AND EQUIPMENT:
  Oil and gas properties, based on successful efforts accounting                   86,970,665        27,943,634
  Other                                                                               529,771           373,258
                                                                                 ------------      ------------
                                                                                   87,500,436        28,316,892
  Less accumulated depreciation, depletion and amortization                       (30,956,448)       (3,446,126)
                                                                                 ------------      ------------
   Property and equipment, net                                                     56,543,988        24,870,766
OTHER ASSETS                                                                          537,983           304,754
                                                                                 ------------      ------------
         Total Assets                                                            $ 59,743,317      $ 27,036,103
                                                                                 ============      ============

                                        LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts payable                                                                  2,829,495         1,439,451
  Accrued expenses                                                                    259,117                --
                                                                                 ------------      ------------
         Total current liabilities                                                  3,088,612         1,439,451
LONG-TERM DEBT                                                                     50,730,894        17,900,000
DEFERRED TAX LIABILITY                                                                350,000                --
OTHER LONG-TERM LIABILITIES                                                           205,116                --
STOCKHOLDERS' EQUITY:
      Common Stock, par value $.01 per share;
      Authorized - 50,000,000 shares; issued 16,373,628 in 1998;                      163,736                -- 
       Treasury Stock -- 61,292 shares                                               (212,070)               --
      Additional paid in capital                                                   25,071,099                -- 
      Retained earnings (deficit)                                                 (19,654,070)               --
      Partners' equity                                                                     --         7,696,652
                                                                                 ------------      ------------
         Total stockholders' equity                                                 5,368,695         7,696,652
                                                                                 ------------      ------------
         Total liabilities and stockholders' equity                              $ 59,743,317      $ 27,036,103
                                                                                 ============      ============
</TABLE>


              The accompanying notes are an integral part of these
                      consolidated financial statements.



                                      F-3
<PAGE>   42



                          VISTA ENERGY RESOURCES, INC.
                     CONSOLIDATED STATEMENTS OF OPERATIONS


<TABLE>
<CAPTION>
                                                                  Years ended December 31,
                                                     ------------------------------------------------
                                                          1998              1997              1996
                                                     ------------      -----------       ------------
<S>                                                  <C>               <C>               <C>         
REVENUES:
   Oil and gas sales                                 $  8,737,056      $  8,874,961      $  5,537,720
                                                     ------------      ------------      ------------
       Total revenues                                   8,737,056         8,874,961         5,537,720
COSTS AND EXPENSES:
        Lease Operating                                 4,398,384         3,688,695         2,544,567
        Exploration Costs                                  32,077            97,211           273,843
        Depreciation, depletion and amortization        3,014,707         2,169,098         1,272,316
        Impairment of oil and gas properties           24,849,632                --                -- 
        General and administrative                      1,743,814           987,020           581,048
        Amortization of Unit Option Awards              4,262,089           315,518                --
                                                     ------------      ------------      ------------
            Total costs and expenses                   38,300,703         7,257,542         4,671,774
                                                     ------------      ------------      ------------
            Operating income (loss)                   (29,563,647)        1,617,419           865,946
        Loss on sale of property                         (317,293)          (87,678)          (56,738)
        Interest income                                     5,833                --                -- 
        Interest expense                               (1,597,350)       (1,048,009)         (476,363)
        Other (expense)/income                            111,745           115,949            61,437
                                                     ------------      ------------      ------------
NET INCOME (LOSS) BEFORE TAXES                        (31,360,712)          597,681           394,282
         Income tax expense (benefit):
           Current                                             --                --                --
            Deferred                                   (6,560,351)               --                --
            Pro Forma                                          --           211,720           139,284
NET INCOME (LOSS)                                    $(24,800,361)     $    385,961      $    254,998
                                                     ============      ============      ============
Earnings (loss) per share:
       Basic and diluted                             $      (1.95)     $        .03      $        .02
                                                     ============      ============      ============
Weighted Average Shares Outstanding (Note 10)          12,687,308        11,903,506        11,903,506
                                                     ============      ============      ============
</TABLE>


              The accompanying notes are an integral part of these
                      consolidated financial statements.


                                      F-4
<PAGE>   43




                          VISTA ENERGY RESOURCES, INC.
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY


<TABLE>
<CAPTION>
                                          Common Stock                       Additional                                  Total
                                    ----------------------    Treasury      Paid in         Retained      Partners'   Stockholders'
                                      Shares       Amount      Stock        Capital         Deficit         Equity       Equity
                                    ----------   ---------   ---------   ------------    ------------   ------------  ------------
<S>                                <C>           <C>         <C>          <C>             <C>           <C>            <C>
BALANCE at December 31, 1995        $       --   $      --   $      --   $         --    $         --   $  6,389,171  $  6,389,171
Net income                                  --          --          --             --              --        394,282       394,282
                                    ----------   ---------   ---------    -----------    ------------   ------------  ------------
BALANCE at December 31, 1996                --          --          --             --              --      6,783,453     6,783,453
Unit option awards                          --          --          --             --              --        315,518       315,518
Net income                                  --          --          --             --              --        597,681       597,681
                                    ----------   ---------   ---------    -----------    ------------   ------------  ------------
BALANCE at December 31, 1997                --          --          --             --              --      7,696,652     7,696,652
Net loss through October 28, 1998           --          --          --             --              --     (5,146,291)   (5,146,291)
Midland Merger                      16,373,628     163,736    (212,070)    25,071,099              --     (6,812,450)   18,210,315
Unit option awards                          --          --          --             --              --      4,262,089     4,262,089
Net loss subsequent to
   Midland Merger                           --          --          --             --     (19,654,070)            --   (19,654,070)
                                    ----------   ---------   ---------   ------------    ------------   ------------  ------------
BALANCE at December  31, 1998       16,373,628   $ 163,736   $(212,070)  $ 25,071,099    $(19,654,070)  $         --     5,368,695
                                    ==========   =========   =========   ============    =============  ============   ===========
</TABLE>




              The accompanying notes are an integral part of these
                      consolidated financial statements.




                                      F-5
<PAGE>   44







                          VISTA ENERGY RESOURCES, INC.
                     CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE>
<CAPTION>
                                                                                    Years ended December 31,
                                                                      ------------------------------------------------
                                                                          1998              1997              1996
                                                                      ------------      ------------      ------------
<S>                                                                   <C>               <C>               <C>         
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss)  before pro forma tax expense ...............     $(24,800,361)     $    597,681      $    394,282
  Adjustments to reconcile net income (loss)
    before taxes to cash provided by
    operating activities:
     Impairment of oil and gas properties .......................       24,849,632                --                --

    Depreciation, depletion and amortization ....................        3,014,707         2,169,098         1,272,316
    Provision for income taxes ..................................       (6,560,351)               --                --

    Amortization of unit option awards ..........................        4,262,089           315,518                --
   Exploration cost .............................................           32,077            97,211           273,843
    Loss on sale of property ....................................          317,293            87,678            56,738
  Changes in working capital
      Increase in Accounts Receivable ...........................         (649,975)         (365,595)         (385,771)
      Increase in other current assets ..........................         (178,699)          (10,594)          (24,120)
      Increase in other non-current assets ......................         (391,100)               --                --
      (Decrease)/Increase in Accounts Payable and 
         accrued expenses .......................................         (520,550)          578,641           485,361
      Decrease in other non-current liabilities .................          (30,395)               --                --
                                                                      ------------      ------------      ------------
      Net cash provided by (used in) operating activities .......         (655,633)        3,469,638         2,072,649
                                                                      ------------      ------------      ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Additions to property and equipment ...........................      (22,805,360)      (13,038,815)       (7,417,091)
  Proceeds from sales of property and Equipment .................          548,364           390,000           390,371
  Payments of organization cost .................................               --                --           (20,000)
                                                                      ------------      ------------      ------------
         Net cash used in investing Activities ..................      (22,256,996)      (12,648,815)       (7,046,720)
                                                                      ------------      ------------      ------------
CASH FLOWS FROM FINANCING ACTIVITIES:

  Payment of borrowings .........................................      (31,446,022)         (418,649)         (400,000)
  Proceeds from issuance of debt ................................       53,831,522         9,703,572         5,415,077
  Payments of debt issuance cost ................................               --           (95,828)               --
                                                                      ------------      ------------      ------------
         Net cash provided by financing Activities ..............       22,385,500         9,189,095         5,015,077
NET INCREASE (DECREASE) IN CASH AND CASH
  EQUIVALENTS ...................................................         (527,129)            9,918            41,006
CASH AND CASH EQUIVALENTS:
  Beginning of period ...........................................          527,129           517,211           476,205
  End of period .................................................     $         --      $    527,129      $    517,211
                                                                      ============      ============      ============
</TABLE>


              The accompanying notes are an integral part of these
                      consolidated financial statements.



                                      F-6
<PAGE>   45





                          VISTA ENERGY RESOURCES, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. ORGANIZATION:

Organization

         Vista Energy Resources, Inc. and its subsidiaries (collectively,
"Vista" or the "Company") is a Delaware corporation whose common stock is
listed and traded on the American Stock Exchange. The Company was incorporated
in May 1998 for the purpose of continuing and consolidating the operations of
Vista Resources Partners, L.P., a Texas limited partnership (the "Vista
Partnership"), and Midland Resources, Inc., a publicly traded Texas corporation
("Midland Resources"). The merger of the Vista Partnership and Midland
Resources (the "Midland Merger") was completed on October 28, 1998. The Company
is an independent oil and gas company engaged in the acquisition, exploration,
production and development of oil and natural gas primarily in the Permian
Basin of West Texas, Southeastern New Mexico and the onshore Gulf Coast region
of South Texas.

         Vista Resources I, Inc., a Texas corporation (the "General Partner"),
now a wholly-owned subsidiary of the Company, serves as the sole general
partner of the Vista Partnership. Vista Resources, Inc., a wholly owned
subsidiary of the Company ("Vista Resources"), currently serves as the operator
of properties in which the Company or its subsidiaries acquires or otherwise
owns operating working interests.

         On October 28, 1998, pursuant to the terms of an Exchange Agreement
dated June 15, 1998 (the "Exchange Agreement"), the Company acquired all of the
outstanding partnership interests of the Vista Partnership and all of the
outstanding shares of common stock of the General Partner in exchange for
shares of Common Stock of the Company (the "Conversion"). The Conversion was
accounted for as a transfer of assets and liabilities between affiliates under
common control and resulted in no change in carrying values of these assets and
liabilities. The Conversion and other transactions contemplated by the Exchange
Agreement were consummated immediately prior to the closing of the Midland
Merger. As a result of the Conversion and the Midland Merger, security holders
of Midland Resources acquired 4,470,123 shares or 27.3 percent of the
outstanding "Common Stock" of the Company, and security holders of the Vista
Partnership acquired 11,903,506 shares of Common Stock, or 72.7 percent.
Accordingly, the accompanying financial statements include the results of
operations of the Company and Midland Resources since October 28, 1998, and the
results of the Vista Partnership prior to that date.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Use of Estimates

         The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the



                                      F-7
<PAGE>   46

reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.

Principles of Consolidation

         The accompanying consolidated financial statements include financial
statements of the Company and its wholly-owned subsidiaries, including Midland
Resources, the General Partner, Vista Resources and Vista Resources Partners,
L.P. All significant intercompany transactions and balances have been
eliminated in preparation of the consolidated financial statements.

Cash and Cash Equivalents

         All highly-liquid investments with original maturities of three months
or less are considered to be cash equivalents.

Accounts Receivable

         Trade receivables represent billings to other working interest owners
for their share of costs on wells for which the Company serves as the operator.

Oil and Gas Properties

         The Company follows the successful efforts method of accounting for
its oil and gas properties whereby costs of productive wells, developmental dry
holes and productive leases are capitalized and amortized on a
unit-of-production basis over the respective properties' remaining proved
reserves. Amortization of capitalized costs of oil and gas properties is
provided on a prospect-by-prospect basis.

         Leasehold costs are capitalized when incurred. Unproved oil and gas
properties with significant acquisition costs are periodically assessed and any
impairment in value is charged to exploration costs. The costs of unproved
properties which are not individually significant are assessed periodically in
the aggregate based on historical experience, and any impairment in value is
charged to exploration costs. The Company recorded $32,077 of such exploration
costs in 1998, $0.1 million of such exploration costs in 1997 and $0.3 million
of such exploration costs in 1996. The costs of unproved properties which are
determined to be productive are transferred to proved oil and gas properties.

         Exploration costs, such as geological and geophysical expenses and
annual delay rentals, are charged to expense as incurred. Exploratory drilling
costs, if any, including the costs, if any, of stratigraphic test wells, are
initially capitalized but charged to expense if and when the well is determined
to be unsuccessful.

         Impairment of Oil and Gas Properties

         The Company has adopted the provisions of Statement of Financial
Accounting Standards ("SFAS 121"), "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of." SFAS 121 requires that
proved oil and gas properties be assessed for an impairment in their carrying
value whenever events or changes in circumstances indicate that such carrying
value may not be recoverable. SFAS 



                                      F-8
<PAGE>   47

121 requires that this assessment be performed by comparing the undiscounted
future net cash flows and net carrying value of oil and gas properties. This
assessment must generally be performed on a property-by-property basis. For the
year ended December 31, 1998, the Company recognized an impairment of its oil
and gas properties in the amount of $24.8 million due to the significant
decline in oil and gas commodity prices realized during 1998, coupled with the
effect of applying purchase accounting to the Midland Merger. No such
impairment of the carrying value of oil and gas properties was required in 1997
or 1996.

         SFAS 121 requires that future revenue from the Company's oil and gas
production be estimated at prices at which management expects such products
will be sold. In evaluating its oil and gas properties for impairment at
December 31, 1998, management has estimated such future product prices at
levels which it believes are reasonable and supportable, but which exceed the
current market prices for oil and gas. Any downward revisions to management's
estimates of product prices could result in additional impairments of its oil
and gas properties in future periods.

Other Property and Equipment

         Other property and equipment are comprised of furniture, office
equipment, fixtures and automobiles. These items are amortized on a
straight-line basis over their estimated useful lives, which range from five to
seven years.

Other Assets

         Other assets are primarily comprised of deferred debt issuance costs
and are presented net of accumulated amortization in the financial statements.
The Company expensed all previously capitalized organization costs and the debt
issuance costs associated with its former bank financing with Union Bank of
California in accordance with SOP 98-5, "Reporting on the Costs of Start-Up
Activities" totalling $0.6 million. Deferred debt issuance costs associated
with the existing BankBoston, N.A. ("BankBoston") credit facility ($0.4
million) will be amortized over the life of the related debt agreements.

Revenue Recognition Policy

         Revenues are recorded when products have been delivered and services
have been performed. The Company uses the sales method to account for gas
imbalances. Under this method, revenue is recognized based on the cash received
rather than the Company's proportionate share of gas produced. The Company's
imbalances at year ended December 31, 1998, 1997 and 1996 were not significant.

Income Taxes

         Prior to the Conversion, the results of operations of the Company were
included in the tax returns of its owners. As a result, tax strategies were
implemented that are not necessarily reflective of strategies the Company would
have implemented as a taxable entity. In addition, the tax net operating losses
generated by the Company during the period from its inception, September 21,
1995, to the date of the Conversion, October 28, 1998, will not be available to
the Company to offset future taxable income as such benefit accrued to the
owners.



                                      F-9
<PAGE>   48

         In conjunction with the Conversion, the Company adopted SFAS 109,
"Accounting for Income Taxes." Under this method of accounting for income
taxes, 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 enacted tax rates is
recognized in income in the period that includes the enactment date. SFAS 109
requires that the net deferred tax liabilities of the Company on the date of
the Conversion be recognized as a component of income tax expense. The Company
recognized approximately $2.6 million in deferred tax liabilities and income
tax expense as of the date of the Conversion.

         Upon the Conversion, the Company became taxable as a corporation. Pro
forma income tax information presented in the accompanying consolidated
statements of operations, reflects the income tax expense (benefit) and net
income (loss) as if all Vista Partnership income had been subject to corporate
federal income tax, exclusive of the effects of recording the Company's net
deferred tax liabilities upon the Conversion.

Supplemental Cash Flow Information

         Cash paid for interest for the year ended December 31, 1998, 1997 and
1996 was $1.2 million, $0.7 million and $0.2 million, respectively. No amounts
have been paid for income taxes.

Financial Instruments

         The Company uses derivatives on a limited basis to hedge against
interest rate and product prices risks, as opposed to their use for trading
purposes. The Company's policy is to ensure that a correlation exists between
the financial instruments and the Company's pricing in its sales contracts
prior to entering into such contracts. Gains and losses on commodity futures
contracts and other price risk management instruments are recognized in oil and
natural gas revenues when the hedged transaction occurs. Cash flows related to
derivative transactions are included in operating activities.

Accounting for Stock Options

         Upon the Conversion, the Company adopted the provisions of Account
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25"). In accordance with APB 25, no compensation will be recorded for
stock options or other stock-based awards that are granted with an exercise
price equal to or above the common stock price on the date of the grant. The
Company will, however, follow the disclosure requirements of SFAS 123,
"Accounting for Stock-Based Compensation" which requires the Company to present
pro forma disclosures of net income and earnings per share as if compensation
expense was recognized for employee stock options.

Recent Accounting Pronouncements

         In June 1997, the Financial Accounting Standards Board issued SFAS
130, "Reporting Comprehensive Income." SFAS 130 establishes standards for
reporting and displaying of comprehensive income and its components (revenue,
expenses, gains and losses) in a full set of general-purpose financial
statements. For the



                                     F-10
<PAGE>   49

years ended December 31, 1998, 1997 and 1996, the Company reported no
differences between comprehensive income (loss) and net income (loss).

         In June 1997, the FASB issued SFAS 131,"Disclosures about Segments of
an Enterprise and Related Information," which requires reporting of financial
and descriptive information about a company's reportable operating segments.
The Company has identified only one operating segment, which is the exploration
and production of oil and gas.

         In June 1998, the FASB issued Statement of SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," which is required to be adopted
for fiscal years beginning after June 15, 1999. SFAS 133 requires that
derivatives be reported on the balance sheet at fair value and, if the
derivative is not designated as a hedging instrument, changes in fair value
must be recognized in earnings in the period of change. If the derivative is
designated as a hedge, and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability (if applicable) or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in earnings when the offsetting hedged transaction occurs. The definition of
derivatives has also been expanded to include contracts that require physical
delivery of oil and gas if the contract allows for net cash settlement. The
Company primarily uses derivatives to hedge product price and interest rate
risks. These derivatives are recorded at cost, and gains and losses on such
derivatives are reported when the hedged transaction occurs. Accordingly,
adoption of SFAS 133 will have an impact on the reported financial position of
the Company, and although such impact has not been determined, it is currently
not believed to be material. Adoption of SFAS 133 should have no significant
impact on reported earnings, but could materially affect comprehensive income.

Reclassifications

         Certain amounts in the prior periods' financial statements have been
reclassified to conform with the current year presentation.

3. SIGNIFICANT ACQUISITIONS OF OIL AND GAS PROPERTIES AND OTHER ASSETS:

1998 Acquisitions

         On October 28, 1998, the Company completed the Conversion and the
Midland Merger (see Note 1). The Company issued 4,470,123 shares of common
stock and 995,375 warrants with an exercise price of $4.00 to the Midland
Resources shareholders and warrant holders and assumed 261,800 Midland
Resources employee options (which expired without exercise in February 1999).
The Company also assumed 2,522,670 Midland Resources warrants to effect the
Midland Merger. In connection with the Midland Merger, the Company issued
11,903,506 shares of common stock and 8,563,028 warrants with an exercise price
of $4.00 to the Vista Partnership's existing partners so that the security
holders of the Vista Partnership would own 72.7 percent of the Company's
outstanding stock and warrants. The estimated value recorded for the
consideration paid to the Midland Resources shareholders was based on the
market value of the Midland Resources securities at the announcement of the
Midland Merger on May 26, 1998. The allocation of the purchase price for the
assets acquired and liabilities assumed was as follows:



                                     F-11
<PAGE>   50

<TABLE>
<S>                                 <C>           
         Working capital            $    (895,132)
         Oil and gas properties     $  37,296,391
         Debt assumed               $ (10,445,394)
         Deferred income taxes      $  (6,910,351)
                                    -------------

               Purchase Price       $  19,045,514  
                                    =============
</TABLE>

         From the announcement of the Midland Merger in May 1998 to the closing
in October 1998, the trading price of the Midland Resources common stock
declined. In addition, oil prices decreased significantly from May 1998 to
December 1998. Accordingly, at December 31, 1998 the Company recorded a
significant impairment charge to the allocated value of oil and gas properties
recorded in purchase accounting for the Midland Merger. The total impairment
recognized related to the properties acquired from Midland Resources was
approximately $22.2 million.

         On December 18, 1998 (effective date of October 1, 1998), the Company
acquired working interests ranging from 65 percent to 85 percent in a group of
oil and gas producing leases from IP Petroleum Company, Inc. and certain of its
working interest partners. These leases are located primarily in the War-Wink
area of Ward and Winkler Counties, Texas, and the interests were acquired for a
purchase price of $19.1 million (the "IP Acquisition"). Collectively, the
Midland Merger and the IP Acquisition are referred to herein as the "1998
Acquisitions."

Pro Forma Condensed Statements of Operations

         The following unaudited Pro Forma Condensed Combined Statements of
Operations for the years ended December 31, 1998 and 1997 give effect to the
1998 and 1997 Acquisitions as if the acquisitions had been consummated at
January 1, 1998 and 1997. The unaudited pro forma data is presented for
illustrative purposes only and is not necessarily indicative of the operating
results that would have occurred had the transactions been consummated at the
dates indicated, nor are they necessarily indicative of future operating
results.

<TABLE>
<CAPTION>
           Pro Forma Condensed Consolidated Statements of Operations
                                  (unaudited)

                                       For the years ended December 31,
                                   --------------------------------------
                                        1998                     1997
                                        ----                     ----
<S>                                <C>                     <C>           
Total revenues                     $  16,784,506           $   25,366,211
Net income (loss)                    (24,667,619)               2,548,993
Basic Net income (loss)                    (1.51)                     .16
Diluted Earnings per share                    --                      .09
</TABLE>




                                     F-12
<PAGE>   51





1997 Acquisitions

         In addition to acquiring various additional small working interests
and overriding royalty interests in properties already owned and operated by
the Company, the Company closed two significant producing property acquisitions
in 1997 (collectively, the "1997 Acquisitions"). In May 1997, the Company
acquired all of the interests of Coastal Oil and Gas Corporation in three
producing leases located in the Howard Glasscock Field, Howard County, Texas,
for a net purchase price of $1.1 million. The interests acquired were
attributable to leases in which the Company already owned interests and which
were operated by the Company.

         Effective as of July 1, 1997, the Company acquired substantially all
of the producing oil and gas properties (representing working interests ranging
from 25 percent to 100 percent in approximately 44 wells located in West Texas,
South Texas, East Texas and Southeastern New Mexico) from E.G. Operating, a
division of FGL, Inc., for a net purchase price of $6.1 million. All of the
Company's 1997 acquisitions were funded through a combination of proceeds from
long-term borrowings and cash provided by operating activities.

1996 Acquisitions

         In addition to acquiring various additional small working interests in
oil and gas properties already owned and operated by the Company, the Company
closed two significant producing property acquisitions in 1996 (collectively,
the "1996 Acquisitions"). Effective as of June 1, 1996, the Company acquired
100 percent of the working interest in two producing leases (14 wells) located
in the Sharon Ridge Field, Scurry County, Texas, for a net purchase price of
$0.5 million.

         Effective as of July 1, 1996, the Company acquired producing oil and
gas properties from Merit Energy Company and certain of its partnership
affiliates for a net purchase price of $4.1 million. All the Company's 1996
acquisitions were funded through a combination of proceeds from long-term
borrowings and cash provided by operating activities.

         All of the acquisitions described above (1998, 1997 and 1996) were
accounted for using the purchase method of accounting. Accordingly, results of
operations from these acquisitions are included in the accompanying financial
statements only as of the closing dates for each of the acquisitions involved.

4. SALE OF OIL AND GAS PROPERTIES:

         During 1998, the Company sold certain oil and gas properties for a
total net consideration of $0.5 million, which resulted in a recognized loss of
$0.3 million. During 1997, the Company sold certain oil and gas properties for
a total net consideration of $0.4 million, which resulted in a recognized loss
of $0.1 million. During 1996, the Company sold certain oil and gas properties
for a total net consideration of $0.4 million, which resulted in a recognized
loss of $0.1 million.

5. OIL AND GAS PRODUCING ACTIVITIES:

         The following table sets forth certain information regarding the
aggregate capitalized costs of oil and gas properties:



                                     F-13
<PAGE>   52

<TABLE>
<CAPTION>
                                                               AS OF DECEMBER 31,
                                                       ------------------------------
                                                            1998             1997
                                                            ----             ----
<S>                                                    <C>               <C>         
Proved properties ................................     $ 86,142,634      $ 27,797,268
Unproved properties ..............................          828,031           146,366
Accumulated depreciation, depletion and
     Amortization ................................      (30,956,448)       (3,396,901)
                                                       ------------      ------------
Net Capitalized Costs ............................     $ 56,014,217      $ 24,546,733
                                                       ============      ============
</TABLE>

         The following table sets forth certain information regarding costs
incurred in connection with the Company's oil and gas producing activities:

<TABLE>
<CAPTION>
                                              As of December 31,
                                   -------------------------------------------
                                       1998            1997            1996
                                   -----------     -----------     -----------
<S>                                <C>             <C>             <C>        
Property acquisitions:
     Proved properties .......     $53,822,839     $ 7,217,464     $ 4,840,602
     Unproved properties .....         681,665          19,295              --
                                                                   -----------
Development costs ............       2,603,396       5,381,429       2,433,838
Exploration costs ............          32,077         176,792         359,763
                                   -----------     -----------     -----------
                                                                        32,077
                                   $57,139,977     $12,794,980     $ 7,634,203
                                   ===========     ===========     ===========
</TABLE>

6. LONG-TERM DEBT:

         As of December 31, 1998, $49.9 million was outstanding under a $100
million revolving Credit Agreement dated December 18, 1998, and accompanying
note (the "Credit Facility") with BankBoston subject to a borrowing base which
is redetermined on a semi-annual basis. The borrowing base at December 31,
1998, was $55 million. The next scheduled borrowing base redetermination is
scheduled for August 31, 1999. Borrowings under the Credit Facility are to be
used for the acquisition and development of oil and gas properties and for
other Company purposes.

         The Company has two options with respect to interest rate elections on
borrowings under the Credit Facility. The Company may either elect an interest
rate equal to (i) the Alternate Base Rate plus the Applicable Margin ("Prime
Basis") or (ii) a Eurodollar rate (i.e., London Interbank Offered Rate) plus
the Applicable Margin ("LIBOR Basis"). The Applicable Margin (as defined in the
Credit Facility) will be adjusted for Borrowing Base usage. The LIBOR Basis
option provides for one-, two-, three-, six- and twelve- month interest
periods. At December 31, 1998, the effective interest rate on the amount
outstanding was 7.5 percent.

         Unless otherwise extended by BankBoston, the Credit Facility converts
to a three-year fully amortizing term loan at December 15, 2001.

         The obligations of the Company under the Credit Facility are secured
by a first lien deed of trust on the Company's interests in certain of its oil
and gas properties.

         The Credit Facility contains two financial covenants including a
minimum current ratio, including available borrowings, of 1:1 and an interest
coverage to EBITDA test (2.0 to 1.0 for the four-fiscal quarter period ending
December 31, 1998; 2.25 to 1.0 for the four-fiscal quarter period ending March
31, 1999; and 2.5 to 1.0 for each four-fiscal quarter period thereafter). The
Credit Facility also includes covenants which, among 



                                     F-14
<PAGE>   53

other things, restrict the incurrence of additional indebtedness and the sale
or acquisition of oil and gas properties above certain levels without the
consent of the lender.

         Effective as of December 23, 1997, the Company entered into an
interest rate swap accounted for as a hedge with any realized gains or losses
appropriately recorded as interest expense (See Note 12 for further discussion
of hedge accounting.). The swap consists of a $10 million notional amount of
indebtedness at a fixed swap rate of 6.02 percent three-month LIBOR for the
Company. The term of this swap ends on December 23, 1999.

         In connection with the Midland Merger, the Company assumed a
settlement obligation with a former officer of Midland Resources. Under the
settlement agreement, the Company is obligated to pay the former officer
$20,000 per month until October 2003. The present value of this agreement is
included in accounts payable ($0.2 million) and long-term debt ($0.8 million)
in the accompanying consolidated financial statements.

         The aggregate maturities of long-term debt at December 31, 1998, are
as follows:

1999                                         None
2000                                  $   196,132
2001                                      208,230
2002                                   16,852,680
2003                                   16,826,217
thereafter                             16,647,635
                                      -----------
Totals                                $50,730,894
                                      ===========

7. EMPLOYEE BENEFIT PLANS:

Stock Option Plan

         In October 1998, the Company adopted its 1998 Key Employee Stock
Option Plan (the "1998 Plan") for key employees of the Company. Under the 1998
Plan, options to acquire up to 900,000 shares of common stock of the Company
may be granted and outstanding at any given time. The specific terms of grant
and exercise are determinable by the Compensation Committee of the Board of
Directors of the Company. No options were issued in 1998. The exercise price
for the options must not be less than the fair market value per common share at
the date of grant. The options vest over a three-year period (33 percent, 66
percent and 100 percent) and expire five years from the date of grant.

Prior Vista Partnership Option Plan

         Effective September 26, 1995, the board of directors of the General
Partner of the Vista Partnership adopted an original Option Plan (the "Plan")
for certain officers and employees of the Vista Partnership and its affiliates.
The Plan authorizes the grant of options to acquire units of limited
partnership interests in the Vista Partnership ("Units"). Effective April 1,
1997, the board of directors of the General Partner of the Vista Partnership
amended and restated the Plan in order to provide for additional options to be
added to the Plan (the



                                     F-15
<PAGE>   54

"Amended Plan"). As of December 31, 1997, the Amended Plan provided for future
awards of options of up to 165,000 Units.

         The Amended Plan provided for the issuance of 1,580,321 options in six
separate series with an initial exercise price of $1 (series A-D or "$1
options") and $2 (series E-F or "$2 options") which were to be increased 10
percent per annum from the initial plan adoption date of September 26, 1995,
for the $1 options and April 1, 1997, for the $2 options. Option A series,
covering 550,358 units, was to vest at a rate of one-third of the options at
each of the dates of April 1, 1998, 1999 and 2000. Option B, C, D and E series
were to vest on the dates that the board determines that the current value of
partnership units had increased by a factor of 3, 4, 5 and 6, respectively, or
on the date that such per unit amounts of cash or other assets have been or are
authorized to be distributed to the partners. Option B, C, D and E series
covered 152,877; 159,826; 167,260 and 350,000 units, respectively.

         Prior to the closing of the Midland Merger, all options under the
Amended Plan vested and such options were exercised by the option holders. At
the closing of the Midland Merger, the Units issued as a result of the exercise
of the options were exchanged for shares of Common Stock of the Company
pursuant to the Exchange Agreement (See Note 1). Accordingly, the Amended Plan
was terminated effective with the closing of the Midland Merger.

         Prior to the closing of the Midland Merger, the Company accounted for
the Units issued under the Amended Plan under Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees." Based on an
estimated fair value of $2 per unit, the Company recorded a noncash charge for
the expected value of the vested $1 options in the amount of $0.3 million for
the year ended December 31, 1997. As a result of the exercise of the options,
the exchange of the Units received pursuant to such exercise under the Exchange
Agreement and the termination of the Amended Plan, the Company recorded a
noncash charge in the amount of $4.3 million for the year ended December 31,
1998. Had compensation cost for the Amended Plan been determined consistent
with SFAS 123, "Accounting for Stock-Based Compensation," the Company would not
have reported any compensation cost related to the Amended Plan for any periods
presented in the accompanying Consolidated Statements of Operations.

401(k) Savings

         The Company has a 401(k) profit sharing and savings plan (the "401(k)
Plan"). The initial plan was established by Midland Resources, however; upon
closing of the Midland Merger, the Company adopted the 401(k) Plan. Eligible
employees may make voluntary contributions to the 401(k) Plan. The amount
contributed by the employees to the 401(k) Plan are limited as specified by the
401(k) Plan. The Company may, at its discretion, make additional contributions
to the 401(k) Plan. The Company has historically made a profit sharing
contribution to the 401(k) Plan in an amount equal to the employees
contribution up to 3 percent of the employees gross salary.

8. COMMITMENTS AND CONTINGENCIES:

         The Company leases 10,963 square feet of office space at 550 West
Texas Avenue, Suite 700 Midland, Texas from Fasken Center, Ltd. under an office
lease dated October 10, 1996 (as amended from time to time, the "Lease"). The
Lease is a non-cancelable operating office lease containing standard and
customary lease 



                                     F-16
<PAGE>   55

provisions and runs from January 1, 1997, through August 31,
2002. The annual rental payments due under the Lease are as follows:


<TABLE>
<CAPTION>
                           PERIOD                             AMOUNT
                           ------                           ---------
             <S>                                           <C>
             September 1, 1997-- August 31, 1998            $  50,523
             September 1, 1998-- August 31, 1999               71,284
             September 1, 1999-- August 31, 2000               86,676
             September 1, 2000-- August 31, 2001               86,676
             September 1, 2001-- August 31, 2002               86,676
                                                            ---------
                                                            $ 381,835
                                                            =========
</TABLE>

         The Company also has office space leased at 616 F. M. 1960 West, Suite
600, Houston, Texas 77090. This lease space is space previously leased by
Midland Resources. The Company is currently attempting to sublease the space in
Houston since it conducts no operations in the Houston area. This lease expires
in 2002 and the annual rental payments of $0.1 million are due until 2002.

Litigation

         At December 31, 1998, the Company was a Defendant in a lawsuit filed
on July 31, 1995, styled Manna Oil & Gas, Inc., Dobbs Oil & Gas, Inc. v.
Midland Resources, Inc. , Miresco Inc., Midland Resources Operating Company,
Inc., Cause No. 40,677. The case involved disputes with a non-operating
interest owner concerning the operation of certain Gulf Coast properties
located in Copano Bay, Aransas County, Texas, wherein the Company owns a 68
percent working interest and is the operator of the properties. The lawsuit was
settled in February 1999 by the Company acquiring all of the interests of the
Plaintiffs in the subject properties for a net purchase price of $0.7 million.

         The Company and its subsidiaries are involved in various other
lawsuits and certain governmental proceedings arising in the ordinary course of
business. Company management and legal counsel do not believe that the ultimate
resolution of these claims will have a material effect on the Company's
financial position or the results of its operations.

9. SIGNIFICANT CUSTOMERS:

         The Company's revenues are derived principally from uncollateralized
sales to customers in the oil and gas industry. The concentration of credit
risk in a single industry affects the Company's overall exposure to credit risk
because customers may be significantly affected by changes in economic and
other conditions. In addition, the Company sells a significant portion of its
oil and natural gas revenue each year to a few customers. Oil and gas sales to
three purchasers in 1998 were approximately 10 percent, 14 percent and 18
percent of total 1998 oil and gas revenues. Oil sales to three purchasers in
1997 were approximately 20 percent, 19 percent and 18 percent of total 1997 oil
and gas revenues. Oil sales to two purchasers in 1996 were approximately 14
percent and 40 percent of total 1996 oil and natural gas revenues.



                                     F-17
<PAGE>   56

         Management does not believe that the loss of any one customer would
have a significant impact on the Company's results of operations.

10. EARNINGS PER SHARE:

         Effective December 31, 1997, the Company adopted the provisions of
SFAS 128, "Earnings Per Share", which prescribes standards for computing and
presenting earnings per share ("EPS") and supersedes APB Opinion 15, "Earnings
Per Share."

         The computation of basic and diluted earnings (loss) per share were
identical for the years ended December 31, 1998, 1997 and 1996 due to the
following:

         Options to purchase 261,800 shares of common stock were outstanding
         since October 28, 1998, but were not included in the computation of
         diluted EPS because the options' exercise price was greater than the
         average market price of the Common Stock. All outstanding options
         expired in February 1999.

         Warrants to purchase 12,081,073 shares of Common Stock were not
         included in the computation of EPS as they are antidilutive as a
         result of the Company's net loss for the year ended December 31, 1998.
         All of these warrants, 11,811,073 of which expire on November 1, 2002,
         with the remaining warrants expiring from March 1999 through June
         2002, were still outstanding at December 31, 1998.

         As the Conversion was not completed until October 28, 1998, there were
         no potentially dilutive equity securities outstanding at either
         December 31, 1997 and 1996.

         EPS has been calculated for all periods presented as if the Conversion
         had been completed on January 1, 1996.

11. INCOME TAXES:

         Upon the Conversion, the Company became taxable as a corporation. Pro
forma income tax information presented in the accompanying statements of
operations, reflects the income tax expense (benefit) and net income (loss) as
if all Vista Partnership income had been subject to corporate federal income
tax, and summarizes the effects of recording the Company's net deferred tax
liabilities upon the Conversion.

         The effective income tax rate for the company was different than the
statutory federal income tax rate for the following reasons:



                                     F-18
<PAGE>   57

<TABLE>
<CAPTION>
                                                                           1998  
                                                                           ----     
<S>                                                                  <C>          
Income tax expense (benefit) at the
   Federal statutory rate of 35 percent ....................          $(10,976,249)
Effect of change in tax status at Conversion ...............             2,635,353
Unit option awards not deductible for Tax ..................             1,491,731
Tax loss generated prior to Conversion .....................               288,814
                                                                      ------------
Income tax expense (benefit) ...............................          $ (6,560,351)
                                                                      ============
</TABLE>

Components of income tax expense (benefit) are as follows:

<TABLE>
<CAPTION>
                                                                          1998
                                                                          -----
<S>                                                                   <C>        
Current income tax .........................................          $        --
Deferred income tax expense (benefit) ......................           (6,560,351)
                                                                      -----------
Income tax expense (benefit) ...............................          $(6,560,351)
                                                                      ===========
</TABLE>

              
         Deferred tax assets and liabilities are the result of temporary
differences between the financial statement carrying values and tax bases of
assets and liabilities. The Company's net deferred tax liabilities are recorded
as a long-term liability of $0.4 million as of December 31, 1998. Significant
components of net deferred tax assets and liabilities are as follows:


<TABLE>
<CAPTION>
                                                                                  December 31,
                                                                                      1998
                                                                                  ------------
<S>                                                                               <C>        
Deferred Tax Assets:
     Net operating loss carryfoward ....................................          $ 2,304,000

Deferred Tax Liabilities:
     Book property basis in excess of tax basis
                                                                                   (2,654,000)
                                                                                  -----------
     Net deferred tax liabilities ......................................          $   350,000
                                                                                  ===========
</TABLE>

         As of December 31, 1998, the Company has estimated tax loss
carryforwards of approximately $6.6 million, which are scheduled to expire in
2001 through 2013.

12. FINANCIAL INSTRUMENTS:

Commodity Price Hedging Instruments

         The Company periodically uses derivative financial instruments to
manage crude oil and natural gas price risk. These instruments qualify as
hedges under generally accepted accounting principles and are properly recorded
as adjustments to oil and gas sales in the consolidated statements of
operations. In order to qualify for hedge accounting, each financial instrument
must be initially designated as a hedge, must appropriately reduce the price
risk and must have correlation to the commodity being hedged. If an instrument
does not qualify as a hedge, then it is accounted for as a speculative
transaction, with any unrealized gains or losses being reflected in the
statement of operations. It is the Company's policy not to engage in
speculative transactions of this nature. If 



                                     F-19
<PAGE>   58

a financial instrument designated as a hedge is sold, extinguished or
terminated before it matures, then the realized gain or loss is deferred and
amortized to oil and gas sales over the original life of the financial
instrument. The Company's realized gains and losses attributable to its price
risk management activities were $0.9 million, $(0.2) million and $(0.6) million
for the years ended December 31, 1998, 1997 and 1996.

         Set forth below is the contract amount and material terms of all crude
oil hedging instruments held by the Company at December 31, 1998 (monthly
volumes are expressed in Bbls and all prices are expressed in the calendar
monthly average of daily NYMEX closing prices for Light Sweet Crude Oil):

<TABLE>
<CAPTION>
    TRADE DATE        TYPE TRANSACTION       MONTHLY VOLUME       PUT FLOOR PRICE     CALL CEILING PRICE            TERM
    ----------        ----------------       --------------       ---------------     ------------------            -----
    <S>               <C>                    <C>                  <C>                 <C>                   <C>
     12-15-97              Collar                10,000             $18.50 Bbl            $19.28 Bbl         4-1-98 to 3-31-99
     12-11-98               Swap                 40,000             $14.20 Bbl            $14.20 Bbl         8-1-99 to 6-30-00
</TABLE>

         Set forth below is the contract amount and material terms of all NYMEX
natural gas hedging instruments held by the Company at December 31, 1998
(monthly volumes are expressed in MMBtus and prices are expressed in the
monthly NYMEX (Henry Hub) closing price for natural gas):

<TABLE>
<CAPTION>
    TRADE DATE         TYPE TRANSACTION       MONTHLY VOLUME       PUT FLOOR PRICE      CALL CEILING PRICE           TERM
    ----------         ----------------       --------------       ---------------      ------------------           -----
    <S>               <C>                     <C>                  <C>                 <C>                   <C>
     8-20-98                Collar                40,000              $2.25 Mcf             $2.45 Mcf         1-1-99 to 12-31-99
     11-12-98               Collar                50,000              $2.25 Mcf             $2.51 Mcf         1-1-99 to 12-31-99
     8-20-98                Collar                40,000              $2.17 Mcf             $2.34 Mcf         1-1-99 to 12-31-99
     12-28-98                Swap                 50,000              $2.01 Mcf             $2.01 Mcf         1-1-99 to 12-31-99
</TABLE>


         The Company also hedges from time to time the basis for its natural
gas production which depends upon the location of its gas production. Such
basis hedges are immaterial to the financial performance of the Company. As of
December 31, 1998, the Company had hedged approximately 21 percent of estimated
1999 oil production and 68 percent of estimated 1999 natural gas production. As
of December 31, 1998, the Company had hedged 19 percent of estimated 2000 oil
production. Subsequent to December 31, 1998, the Company has hedged an
additional 22 percent of 1999 estimated oil production. Subsequent to December
31, 1998, the Company has hedged 42 percent of 2000 estimated natural gas
production and 44 percent of 2001 natural gas production.

Interest Rate Swap Agreement

         Effective as of December 23, 1997, the Company entered into an
interest rate swap accounted for as a hedge with any realized gains or losses
appropriately recorded as interest expense. The swap consists of a $10 million
notional amount of indebtedness at a fixed swap rate of 6.02 percent based on
the three-month LIBOR for the Company. The term of this swap ends on December
23, 1999.

13. OIL AND GAS RESERVES INFORMATION (UNAUDITED):

         The estimates of proved oil and gas reserves utilized in the
preparation of the financial statements were estimated by outside engineers for
1998, and by the Company for 1997 and 1996 in accordance with guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board, which require that reserve reports be prepared
under existing economic and operating conditions with no provision for



                                     F-20
<PAGE>   59

price and cost escalation except by contractual agreement. All of the Company's
reserves are located onshore in or offshore to the continental United States.

         Future prices received for production and future production costs may
vary, perhaps significantly from the prices and costs assumed for purposes of
these estimates. There can be no assurance that the proved reserves will be
developed within the periods indicated or that prices and costs will remain
constant. There can be no assurance that actual production will equal the
estimated amounts used in the preparation of reserve projections. In accordance
with the Securities and Exchange Commission's guidelines, the Company's
estimates of future net cash flows from the Company's proved properties and the
representative value thereof are made using oil and natural gas prices in
effect as of the dates of such estimates and are held constant throughout the
life of the properties. Average prices used in estimating the future net cash
flows at December 31, 1998, 1997 and 1996 were as follows: $10.64, $16.10 and
$23.55 per barrel for oil, respectively, and $1.83, $2.01 and $3.43 per Mcf for
natural gas, respectively.

         There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in any exact way, and estimates of other
engineers might differ materially from those shown below. The accuracy of any
reserve estimate is a function of the quality of available data and engineering
and estimates may justify revisions. Accordingly, reserves estimates are often
materially different from the quantities of oil and gas that are ultimately
recovered. Reserve estimates are integral in management's analysis of
impairments of oil and gas properties and the calculation of depreciation,
depletion and amortization on its properties.

         The following unaudited table sets forth proved oil and gas reserves
at December 31, 1998, 1997 and 1996:

<TABLE>
<CAPTION>
                                                                      For the Years Ended December 31,
                                   ----------------------------------------------------------------------------------------------
                                               1998                              1997                            1996
                                               ----                              ----                            ----
                                       Oil            Gas                Oil              Gas             Oil              Gas
                                      (Bbls)         (Mcf)             (Bbls)            (Mcf)           (Bbls)           (Mcf)
                                   ----------       ----------        ---------       ----------       ----------        ---------
<S>                                 <C>             <C>               <C>              <C>              <C>              <C>      
Proved Reserves:
      Beginning of year .......     7,216,559       11,295,325        4,540,419        7,185,636        2,230,190        4,837,030
      Revisions of previous
         Estimates ............    (1,669,606)      (2,576,510)       1,304,819         (969,377)         548,009         (458,198)
      Extensions and
         Discoveries ..........       465,458        4,182,533        1,161,953               --          205,859           28,442
      Purchase of minerals in
         place ................     5,118,101       20,024,034          762,282        6,206,929        1,838,595        3,339,214
      Sale of minerals in
         Place ................      (142,316)         (28,925)        (148,902)        (343,565)         (46,455)        (126,680)
      Production ..............      (529,426)      (1,250,490)        (403,812)        (784,298)        (235,779)        (434,172)
                                   ----------       ----------        ---------       ----------       ----------        ---------
      End of year .............    10,458,770       31,645,967        7,216,759       11,295,325        4,540,419        7,185,636
                                   ==========       ==========        =========        =========        =========        =========
Proved Developed Reserves:
       Beginning of year ......     3,559,850        7,909,902        3,092,149        5,510,499        1,352,870        3,893,360
                                   ----------       ----------        ---------       ----------       ----------        ---------
       End of  year ...........     6,708,844       22,613,532        3,559,850        7,909,902        3,092,149        5,510,499
                                   ==========       ==========        =========        =========        =========        =========
</TABLE>


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

(1)      Proved reserves have historically been revised upward as a result of
         successful in-field drilling and implementation of secondary recovery
         projects which result in the reclassification of "probable" reserves
         to the "proved" category. Other less significant revisions occurred
         and are attributable to properties Vista purchased which, as a result
         of additional in-depth geological and engineering reviews, were
         determined to have additional proved reserves (i.e., more than were
         originally identified at the time of purchase). During 1998, negative
         reserve revisions were the result of significantly lower prices from
         the previous year.



                                     F-21
<PAGE>   60

         The following table sets forth the standardized measure of discounted
future net cash flows relating to proved reserves at December 31, 1998, 1997
and 1996:


<TABLE>
<CAPTION>
                                                       1998               1997               1996
                                                  -------------      -------------      -------------
<S>                                               <C>                <C>                <C>          
Cash Flows Relating to Proved Reserves:
   Future cash flows ........................     $ 170,551,299      $ 131,921,276      $ 125,076,627
   Future costs:
      Production ............................       (69,536,325)       (45,194,356)       (47,139,363)
      Development ...........................       (15,369,172)       (12,371,206)        (6,835,546)
    Income taxes ............................       (10,032,197)                --                 --
                                                  -------------      -------------      -------------
   Future net cash flows ....................        75,613,605         74,355,714         71,101,718
   10% discount factor ......................       (25,376,691)       (35,775,170)       (30,250,175)
                                                  -------------      -------------      -------------
Standardized measure of discounted 
  Future net cash flows .....................     $  50,236,914      $  38,580,544      $  40,851,543
                                                  =============      =============      =============
</TABLE>

         Had the Company been a taxable entity at December 31, 1997, the future
income taxes would have been $14.1 million on an undiscounted basis and $7.8
million on a discounted basis, and the standardized measure of discounted
future net cash flows at December 31, 1997 would have been $37.0 million.

         The following table sets forth the changes in the standardized measure
of discounted future net cash flows relating to proved reserves for the years
ended December 31, 1998, 1997 and 1996:

<TABLE>
<CAPTION>
                                                                           1998              1997              1996
                                                                      ------------      ------------      ------------
<S>                                                                   <C>               <C>               <C>         
Standardized Measure, Beginning of Year .........................     $ 38,580,544      $ 40,851,543      $ 17,242,730
     Net change in sales prices, net of production costs ........      (17,336,320)      (12,557,771)        6,601,987
     Development costs incurred during the year which
         were previously estimated ..............................        3,000,000         5,073,000         2,033,000
     Revisions of quantity estimates ............................       (6,361,075)        6,325,872         4,182,057
     Extensions, discoveries and improved recovery, net of
     future production and development costs ....................        4,296,455         2,382,351         1,485,041
     Accretion of discount ......................................        3,858,054         4,085,154         1,724,273
     Change in future development costs .........................        4,484,697        (4,116,068)       (2,598,316)
     Change in timing and other .................................       (2,830,538)       (5,394,793)       (4,484,968)
     Change in future income taxes ..............................               --                --                --
     Purchases of reserves in place .............................       27,382,247         8,289,041        17,756,033
     Sales of reserves in place .................................         (498,478)       (1,171,519)          (97,141)
     Sales, net of production costs .............................       (4,338,672)       (5,186,266)       (2,993,153)
                                                                      ------------      ------------      ------------
Standardized measure, End of Year ...............................     $ 50,236,914      $ 38,580,544      $ 40,851,543
                                                                      ============      ============      ============
</TABLE>


                                     F-22
<PAGE>   61

INDEX TO EXHIBITS


<TABLE>
<CAPTION>
        Exhibit 
          No.                Description
       --------              -----------
       <S>        <C>
         10.13    Credit Agreement, dated December 18, 1998 by and between
                  Vista Resources Partners, L.P. and Midland Resources, Inc.,
                  as borrowers, Vista Energy Resources, Inc., as guarantor,
                  BancBoston Robertson Stephens Inc., as arranger and
                  syndication agent, BancBoston, N.A., as administrative agent
                  and certain financial institutions.

         21.1     Subsidiaries of Vista Energy Resources, Inc.

         23.1     Independent Auditors Consent.

         27.1     Financial Data Schedule
</TABLE>