MISSION RESOURCES CORP - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

OR

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

COMMISSION FILE NUMBER 0-9498

MISSION RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 76-0437769
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1331 LAMAR, SUITE 1455, 77010-3039
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(713) 495-3000

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

COMMON STOCK, $0.01 PAR VALUE
SERIES A PREFERRED STOCK PURCHASE RIGHTS

Indicate by check mark whether the registrant (1) has filed all reports
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months 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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [ ] No [X]

The aggregate market value of the voting stock held by non-affiliates of
the registrant at June 30, 2003 was approximately $49,030,863.

As of March 5, 2004, the number of outstanding shares of the registrant's
common stock was 34,267,636.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 2003, are incorporated by reference into Part III of
this Form 10-K.

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2003

TABLE OF CONTENTS

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PART I

FORWARD LOOKING STATEMENTS

This annual report on Form 10-K includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended ("Exchange Act"). All statements other than statements of historical
fact are forward-looking statements. Forward-looking statements are subject to
certain risks, trends and uncertainties that could cause actual results to
differ materially from those projected. Among those risks, trends and
uncertainties are our estimate of the sufficiency of existing capital sources,
our highly leveraged capital structure, our ability to raise additional capital
to fund cash requirements for future operations, the uncertainties involved in
estimating quantities of proved oil and natural gas reserves, in prospect
development and property acquisitions and in projecting future rates of
production, the timing of development expenditures and drilling of wells, and
the operating hazards attendant to the oil and gas business. Although we believe
that in making such forward-looking statements our expectations are based upon
reasonable assumptions, such statements may be influenced by factors that could
cause actual outcomes and results to be materially different from those
projected. We cannot assure you that the assumptions upon which these statements
are based will prove to have been correct.

When used in this Form 10-K, the words "expect", "anticipate", "intend,"
"plan," "believe," "seek," "estimate" and similar expressions are intended to
identify forward-looking statements, although not all forward-looking statements
contain these identifying words. Because these forward-looking statements
involve risks and uncertainties, actual results could differ materially from
those expressed or implied by these forward-looking statements for a number of
important reasons, including those discussed under "Management's Discussions and
Analysis of Financial Condition and Results of Operations," "Risk Factors" and
elsewhere in this Form 10-K.

You should read these statements carefully because they discuss our
expectations about our future performance, contain projections of our future
operating results or our future financial condition, or state other
"forward-looking" information. Before you invest in our common stock, you should
be aware that the occurrence of any of the events described in "Management's
Discussions and Analysis of Financial Condition and Results of Operations,"
"Risk Factors" and elsewhere in this Form 10-K could substantially harm our
business, results of operations and financial condition and that upon the
occurrence of any of these events, the trading price of our common stock could
decline, and you could lose all or part of your investment.

We cannot guarantee any future results, levels of activity, performance or
achievements. Except as required by law, we undertake no obligation to update
any of the forward-looking statements in this Form 10-K after the date of this
Form 10-K.

As used in this annual report, the words "we", "our", "us", "Mission" and
the "Company" refer to Mission Resources Corporation, its predecessors and
subsidiaries, except as otherwise specified.

Terms specific to the oil and gas industry may be used in this Form 10-K.
For explanation of technical terms, refer to the "Glossary of Oil and Gas Terms"
at the end of this Form 10-K.

ITEM 1. & 2. BUSINESS AND PROPERTIES

GENERAL

Mission Resources Corporation is an independent oil and gas exploration and
production company headquartered in Houston, Texas. We drill for, acquire,
develop and produce natural gas and crude oil primarily, in the Permian Basin
(in West Texas and Southeast New Mexico), along the Texas and Louisiana Gulf
Coast and in both the state and federal waters of the Gulf of Mexico. At
December 31, 2003, our estimated net proved reserves, using constant prices
which were in effect at such date, were 85.1 billion cubic feet ("BCF") of
natural gas, 10.4 billion cubic feet equivalents ("BCFE") of natural gas liquids
("NGLs") and 13.7 million barrels ("MMBBL") of oil, for total reserves of
approximately

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178 BCFE. Approximately 54% of the estimated net proved reserves were natural
gas or NGLs, and approximately 75% of the reserves were developed at December
31, 2003. On January 30, 2004, we closed the $26.6 million acquisition of the
Jalmat field in the Permian Basin. This acquisition adds approximately 26 BCFE
of proved reserves and brings our percentage of natural gas and NGLs to 59%.

OUR BUSINESS STRATEGY AND COMPETITIVE STRENGTHS

During 2002, our new management team began to reduce leverage, refinance
indebtedness, focus on natural gas, and expand our oil and gas reserves through
exploration and development and targeted acquisitions. We intend to build upon
the progress we have made in these areas by executing our business strategy to:

- Reduce leverage and increase operational flexibility. Since March 2003,
through a combination of debt repurchases and equity for debt exchanges,
we have eliminated over $43 million of indebtedness, reduced our debt as
a percentage of book capitalization from 78% to 67% and reduced annual
interest expense by approximately $3.7 million. We intend to further
reduce leverage as we move toward our long term goal of debt as a
percentage of book capital of 50%.

- Establish natural gas as our primary product. We have made progress
toward our goal of a 70% natural gas to 30% oil production mix, and we
are continuing to focus on the exploration and development of natural gas
reserves in our core geographic areas. After the Jalmat acquisition in
January 2004, natural gas represents 59% of our total production, up from
41% in the fourth quarter of 2002.

- Reduce our unit operating expense. In order to lower unit operating
expenses, we sold certain assets which had high operating costs,
including our offshore California, East Texas and Raccoon Bend
properties. These asset sales, combined with new production from our
drilling programs, helped to reduce our operating expenses per MCFE from
$1.42 in the fourth quarter of 2002 to $1.24 in fourth quarter of 2003.
In January 2004, we redeployed funds from asset sales to acquire our
interest in the Jalmat field in the Permian Basin. This field, with its
ongoing operating expenses of approximately $0.70 per MCFE will help
further reduce our unit operating expenses. We expect to make further
reductions in unit costs, as reflected in our 2004 operating expense
guidance of between $1.15 to $1.25 per MCFE.

- Manage our portfolio of assets. We are actively developing our assets to
maximize their value and conducting field studies to find additional
opportunities to enhance the performance of our properties. Our goal is
to balance long life properties with high rate, high decline properties.
Our strategy is to limit our capital expenditures to no more than our
discretionary cash flow. In 2003, we spent $34.4 million drilling 48
wells, of which 42 were successful. In addition to acquiring the Jalmat
field, we plan to spend $32-34 million in 2004 on capital expenditures.
In order to protect our cash flows, to the extent possible, we intend to
hedge forward 12 months up to 75% of our proved developed production, and
up to 50% of the following 12 months proved developed production.

- Utilize our exploration team to develop prospects and maintain low
finding and development costs. During 2003, we assembled an exploration
team of geophysicists and geologists with expertise in the industry and
in our core areas. Utilizing our existing 3-D seismic library and newly
acquired data sets, this team is developing natural gas prospects,
primarily in the Gulf Coast onshore area. This team is skilled in using
seismic reprocessing, new seismic surveys, reservoir simulation and
sophisticated drilling and completion techniques. In 2003, our efforts
reduced our finding and development costs to $1.27 per MCFE, and in 2004
we intend to continue our efforts to find reserves on a cost effective
basis.

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OUR OIL AND GAS PROPERTIES

RESERVES

Our estimated net proved oil and gas reserves at December 31, 2003 were
approximately 178 BCFE. We replaced production through reserve additions and
extensions and also had positive reserve revisions. As part of our strategy to
reduce unit costs and increase our percentage of production from natural gas, we
sold 55 BCFE of high operating cost reserves, primarily oil, in 2003. Set forth
below is a reconciliation of our yearend 2003 reserves, as compared to our
yearend 2002 reserves, based upon the evaluation of reserves by Netherland,
Sewell & Associates, Inc. The reserves were calculated using SEC yearend
pricing:

In January 2004, we acquired the Jalmat field for $26.6 million. This
acquisition added approximately 26 BCFE to the amount of our reserves shown
above.

In general, estimates of economically recoverable oil and natural gas
reserves and of the future net cash flows therefrom are based upon a number of
factors, such as historical production from the properties, assumptions
concerning future oil and natural gas prices, future operating costs and the
assumed effects of regulation by governmental agencies, all of which may vary
considerably from actual results. All such estimates are to some degree
speculative, and classifications of reserves are only attempts to define the
degree of speculation involved. Estimates of the economically recoverable oil
and natural gas reserves attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of
future net cash flows expected therefrom, prepared by different engineers or by
the same engineers at different times, may vary. Mission's actual production,
revenues, severance and excise taxes and development and operating expenditures
with respect to its reserves will vary from such estimates, and such variances
could be material.

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

In accordance with applicable requirements of the Securities and Exchange
Commission, the discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless prices or
costs subsequent to that date are contractually determined. Actual future prices
and costs may be materially higher or lower than prices or costs as of the date
of the estimate. Actual future net cash flows also will be affected by factors
such as actual production, supply and demand for oil and natural gas,
curtailments or increases in consumption by natural gas purchasers, changes in
governmental regulations or taxation and the impact of inflation on costs. See
"Risk Factors" for a discussion of the uncertainties inherent in preparing
reserve estimates.

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PRODUCTION

The following table sets forth our net production and net proved reserves
as of and for the year ended December 31, 2003 by geographic area.

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

(1) In accordance with Securities and Exchange Commission requirements, the
estimated discounted future net cash flows are based on prices and costs as
of the date of the estimate. The average prices on December 31, 2003 for
natural gas and oil used in our estimate were $5.97 per MMBTU and $32.47 per
BBL.

The acquisition of the Jalmat field in January 2004 added approximately $42
million to the amount of the December 31, 2003 discounted future net cash flows
that are shown above.

Data relating to production volumes, production costs and oil and gas
reserve information are contained in Note 16 of the Notes to Consolidated
Financial Statements

The following table provides summary statistics about our most significant
properties by geographic area as of December 31, 2003.

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

(1) Because most reserves are undeveloped at yearend and 2003 production was
low, this measure is not useful for these individual fields.

(2) Includes isolated property interests in Wyoming, Oregon, and Oklahoma.

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PERMIAN BASIN AREA

Waddell Field

Waddell Field is a large, mature property consisting of 1,600 producing
wells that produces oil and gas from various Permian age formations ranging in
depth from 3,000 to 5,000 feet. The property, which covers over 75,000 acres, is
located in the Permian Basin in Crane County, Texas. Burlington Resources is the
operator and Mission's interest is approximately 10%. A portion of the field is
under waterflood. The field is under continuous development predominantly by
means of well recompletions and workovers.

TXL North Unit

The TXL North Unit is an active waterflood unit that consists of 225 wells
and produces from the Tubb formation at a depth of approximately 5,500 feet.
Anadarko Petroleum Corporation operates the property, located in the Permian
Basin in Ector County, Texas, and Mission holds an approximate 20% working
interest and 25% net revenue interest. A 10-acre infill development program was
initiated in 2003, with the successful drilling of twenty wells, and continues
with additional drilling which began in early 2004.

Wasson Field

Mission holds an approximate 36% working interest in the Brahaney Unit,
located in the Permian Basin in Yoakum County, Texas. Apache Corporation
operates this waterflood unit that consists of 95 producing wells and produces
from the San Andres formation at a depth of 5,500 feet. Production has increased
significantly in past few years as a result of a successful infill drilling
program. In 2003, ten wells were drilled and the development drilling program
continues.

Goldsmith Field

The Goldsmith Field consists primarily of the CA Goldsmith Unit, operated
by Chevron-Texaco, and is located in the Permian Basin in Ector County, Texas.
Mission holds a 25% working and net revenue interest in this property. The field
consists of 250 producing wells with production primarily from the Clearfork and
Devonian formations at depths ranging from 5,500 to 8,000 feet.

Jalmat Field (2004 Acquisition)

The January 2004 acquisition of the Jalmat field, added approximately 26
BCFE to our proved reserves. Mission is the operator of this field and our
average working interest is approximately 80%. This field produces primarily
from the Yates and 7-Rivers formations at depths ranging from 3,000 to 4,200
feet. Gas production from the Yates and 7-Rivers has a high heating content and
is processed at a nearby plant to yield significant volumes of natural gas
liquids. Numerous behind pipe recompletions and infill drilling potential exist
in both the Yates and 7-Rivers formations. Additionally, the deeper Queen
formation may have waterflood potential.

GULF COAST AREA

North Leroy Field

North Leroy is a natural gas field located in Vermilion Parish, Louisiana
and produces from multiple Frio-age reservoirs at depths ranging from 11,500 to
13,000 feet. Mission operates one of the three producing wells with an average
working interest of 81%. One well was drilled in 2003 and several recompletion
candidates have already been identified.

Reddell Field

Reddell Field is a natural gas field located in Evangeline Parish,
Louisiana that produces from the Upper, Middle and Lower Wilcox at depths
ranging from 10,000 to 13,000 feet. Burlington Resources

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operates the field consisting of 21 producing wells. In 2003, one well was
drilled and three wells were successfully recompleted to the upper Wilcox.
Mission holds a 15% working interest in the field, in which additional
development opportunities exist.

South Bayou Boeuf

South Bayou Boeuf Field is located in LaFourche Parish, Louisiana and
produces from various Miocene-age formations at depths ranging from 10,000 to
12,500 feet. Mission operates the field and holds an average working interest of
96% in the six producing wells. Reserve upside exists in development drilling
updip to productive wells.

GULF OF MEXICO AREA

High Island Block A-553

Mission operates this property located offshore Louisiana in federal waters
(water depth of 260 feet). The field produces from Pleistocene and Pliocene
formations ranging from 5,000 to 12,000 feet. Production and reserves are
primarily gas with liquid condensate. In 2003, Mission acquired an additional
minor interest in the property, increasing its working interest to approximately
37%. The block contains one platform and six wells. Recompletion and drilling
opportunities exist on this block.

South Marsh Island Block 142

Located in federal waters (water depth of 230 feet), offshore Louisiana,
South Marsh Island Block 142 produces oil and gas from Pleistocene and Pliocene
formations at depths ranging from 3,000 to 7,000 feet. Mission holds an
approximate 31% working interest and Hunt Petroleum, Inc. is the operator of
this property. The field contains two platforms and 16 wells, including two
successful development wells drilled in 2003. There are additional development
drilling and recompletion opportunities on this block.

HISTORICAL DRILLING ACTIVITY

Our principal drilling activities during the last three years were focused
on properties in the Permian Basin, along the Texas and Louisiana Gulf Coast and
in the Gulf of Mexico. The following tables set forth the results of drilling
activity for the last three years:

EXPLORATORY WELLS

DEVELOPMENT WELLS

One well was in progress as of December 31, 2003.

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OUR INTEREST IN PRODUCTIVE WELLS

The following table sets forth the number of productive oil and gas wells
in which we own interests as of December 31, 2003. Productive wells are defined
as producing wells and wells capable of production. Gross wells are the number
of wells in which we own a working interest. The number of net wells is the sum
of the fractional ownership of working interests that we own directly in gross
wells. Therefore, the number of net wells does not represent a number of actual,
physical wells, but rather quantifies the actual total working interests we hold
in all wells. We compute the number of net wells by adding together the
percentage of interests we hold in all our gross wells.

OUR ACREAGE

The following table sets forth information concerning our developed and
undeveloped oil and gas acreage as of December 31, 2003. Undeveloped acreage
consists of those leased acres on which wells have not been drilled or completed
to a point that would permit the production of commercial quantities of oil and
gas, regardless of whether or not such acreage contains proved reserves. The
number of gross acres in the following table refers to the total number of acres
in which we own a working interest. The number of net acres is the sum of the
fractional ownership of working interests that we own in the gross acres. All of
our developed and undeveloped acreage is located in the United States and its
territorial waters.

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The primary terms of our oil and natural gas leases expire at various
dates. Some of our undeveloped acreage is "held by production", which means that
these leases are active as long as we produce oil or natural gas from the
acreage. Upon ceasing production, these leases will expire.

OUR PRINCIPAL MARKETS AND CUSTOMERS

We sell our natural gas and oil production under fixed or floating market
price contracts. Our revenues, profitability, cash flow and future growth depend
substantially on prevailing prices for natural gas and oil. Among the factors
that can cause this fluctuation are the level of consumer product demand,
weather conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions and actual or threatened
acts of war, terrorism or hostilities in oil producing regions, the domestic and
foreign supply of natural gas and oil, the price of foreign imports and overall
economic conditions.

Decreases in the prices of natural gas and oil could adversely affect the
carrying value of proved reserves and revenues, profitability and cash flow.
Although we are not currently experiencing any curtailment of natural gas or oil
production, market, economic and regulatory factors may in the future materially
affect our ability to sell natural gas or oil production.

In 2003, sales of oil and natural gas to Shell Trading (US) Company
accounted for approximately 21.5% of our oil and gas revenues, and no other
purchaser accounted for more than 10% of our oil and gas revenues. If we were to
lose any one (including Shell Trading (US) Company) of our oil and natural gas
purchasers, the loss could temporarily delay production and sale of our oil and
natural gas in the particular purchaser's service area; however, we believe that
we could quickly identify a substitute purchaser. In 2002, no single customer
accounted for more than 10% of our oil and gas revenues. During 2002, several
large wholesale purchasers of natural gas experienced significant downgrades in
their credit ratings. As a result, many of these companies have either reduced
their level of natural gas purchases or have discontinued their purchases of
natural gas. Although we do not believe that we have been significantly impacted
by these changes, the loss of these large natural gas purchasers could have a
detrimental effect on the natural gas market in general and on our ability to
find purchasers for our natural gas. When we deem it necessary or prudent we
require letters of credit, parent company guarantees or other forms of credit
enhancement from our purchasers.

We enter into hedging arrangements from time to time to reduce our exposure
to fluctuations in natural gas and oil prices and to achieve more predictable
cash flow. However, these hedging arrangements also limit the benefits we would
realize if prices increase. These financial arrangements take the form of swap
contracts or cashless collars and are placed with major trading counter parties
we believe represent minimal credit risks. We cannot assure you that these
trading counter parties will not become credit risks in the future. For further
information concerning our hedging transactions, see "Item 7A. Quantitative and
Qualitative Disclosures about Market Risk."

OUR COMPETITION

The oil and natural gas industry is highly competitive. We compete with
both independent operators and major oil companies in all areas of our
operations, including acquiring properties, contracting for drilling equipment
and securing trained personnel. Many of these competitors have greater financial
and technical resources and substantially larger staffs than we do. As a result,
our competitors may be able to pay more for desirable leases, or to evaluate,
bid for and purchase a greater number of properties or prospects than our
financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability
of related equipment. In the past, the oil and natural gas industry has
experienced shortages of drilling rigs, equipment, pipe and personnel, which has
delayed development drilling or other activities and has caused significant cost
increases. We are unable to predict when, or if, such shortages may again occur
or how they would affect exploration and exploitation plans.

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Competition is also strong for attractive oil and natural gas producing
properties, undeveloped leases and drilling rights. Many large oil companies
have been actively marketing some of their existing producing properties for
sale to independent producers. We cannot assure you that we will be able to
compete for these properties successfully.

APPLICABLE LAWS AND REGULATIONS

UNITED STATES REGULATIONS

Sales and Transportation of Gas

Historically, the sale or resale of natural gas in interstate commerce has
been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas
Policy Act of 1978 ("NGPA") and the regulations promulgated hereunder by the
Federal Energy Regulatory Commission ("FERC"). In the past, the federal
government has regulated the prices at which natural gas could be sold.
Deregulation of natural gas sales by producers began with the enactment of the
NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which
removed all remaining NGA and NGPA price and non-price controls affecting
producer sales of natural gas effective January 1, 1993. Congress could,
however, re-enact price controls in the future.

Mission's sales of natural gas are affected by the availability, terms and
cost of transportation. The rates, terms and conditions applicable to the
interstate transportation of gas by pipelines are regulated by the FERC under
the NGA, as well as under section 311 of the NGPA. Since 1985, the FERC has
implemented regulations intended to increase competition within the gas industry
by making gas transportation more accessible to gas buyers and sellers on an
open-access, non-discriminatory basis.

The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines
operating on or across the Outer Continental Shelf ("OCS") provide open-access,
non-discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, in which the FERC implemented the OCSLA, on
gatherers and other non-jurisdictional entities, the FERC has retained the
authority to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the OCS. FERC also issued Order No. 639,
requiring that virtually all non-proprietary pipeline transporters of natural
gas on the OCS report information on their affiliations, rates and conditions of
service. Among the FERC's stated purposes in issuing such rules was the desire
to provide shippers on the OCS with greater assurance of open-access services on
pipelines located on the OCS and non-discriminatory rates and conditions of
service on such pipelines. A federal district court recently determined that
FERC has exceeded its statutory authority in promulgating Order Nos. 639 and
639-A, and the court permanently enjoined FERC from enforcing the orders. FERC
has appealed the district court's decision.

FERC has announced several important transportation-related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000, concerning alternatives to its traditional
cost-of-service ratemaking methodology to establish the rates interstate
pipelines may charge for their services. The final rule revised FERC's pricing
policy and current regulatory framework to improve the efficiency of the market
and further enhance competition in natural gas markets.

Sales and Transportation of Oil

Sales of oil and condensate can be made at market prices and are not
subject at this time to price controls. The price received from the sale of
these products will be affected by the cost of transporting the products to
market. FERC regulations govern the rates that may be charged by oil pipelines
by use of an indexing system for setting transportation rate ceilings. In
certain circumstances, rules permit oil pipelines to establish rates using
traditional cost of service and other methods of rate making.

Legislative Proposals

In the past, Congress has been very active in the area of gas regulation.
In addition, there are legislative proposals pending in the state legislatures
of various states, which, if enacted, could significantly

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affect the petroleum industry. At the present time it is impossible to predict
what proposals, if any, might actually be enacted by Congress or the various
state legislatures and what effect, if any, such proposals might have on our
operations.

Federal, State or Indian Leases

To the extent that we conduct operations on federal, state or Indian oil
and gas leases, such operations must comply with numerous regulatory
restrictions, including various nondiscrimination statutes, and certain of such
operations must be conducted pursuant to certain on-site security regulations
and other appropriate permits issued by the Bureau of Land Management ("BLM")
or, in the case our OCS leases in federal waters, Minerals Management Service
("MMS") or other appropriate federal or state agencies. Mission's OCS leases in
federal waters are administered by the MMS and require compliance with detailed
MMS regulations and orders. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the OCSLA that are subject to interpretation
and change by the MMS. For offshore operations, lessees must obtain MMS approval
for exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the MMS prior
to the commencement of drilling. The MMS has promulgated regulations requiring
offshore production facilities located on the OCS to meet stringent engineering
and construction specifications. The MMS also has regulations restricting the
flaring or venting of natural gas, and has proposed to amend such regulations to
prohibit the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the installation and removal of all
production facilities. Under some circumstances, the MMS may require any of our
operations on federal leases to be suspended or terminated.

To cover the various obligations of lessees on the OCS, the MMS generally
requires that lessees have substantial net worth or post bonds or other
acceptable assurances that such obligations will be met. The cost of these bonds
are not currently material, but could become substantial if we expand our areas
of operations. There is no assurance that bonds or other surety can be obtained
in all cases. We are currently in compliance with the bonding requirements of
the MMS. Any such suspension or termination could materially adversely affect
Mission's financial condition and results of operations.

On March 15, 2000, the MMS issued a final rule effective June 2000, which
amended its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. Among other matters, this rule amends
the valuation procedure for the sale of federal royalty oil by eliminating
posted prices as a measure of value and relying instead on arm's length sales
prices and spot market prices as market value indicators. Because Mission sells
most of its production at spot market prices and, therefore, pays royalties on
production from federal leases based on spot prices, it is not anticipated that
this final rule will have a material impact on Mission.

The Mineral Leasing Act of 1920 (the "Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a
"non-reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect. We
own interests in numerous federal onshore oil and gas leases. It is possible
that our common stock will be acquired by citizens of foreign countries, which
at some time in the future might be determined to be non-reciprocal under the
Mineral Act.

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STATE REGULATIONS

Most states regulate the production and sale of oil and gas, including:

- requirements for obtaining drilling permits,

- the method of developing new fields,

- the spacing and operation of wells,

- the prevention of waste of oil and gas resources, and

- the plugging and abandonment of wells.

The rate of production may be regulated and the maximum daily production
allowable from both oil and gas wells may be established on a market demand or
conservation basis or both.

Mission owns certain natural gas pipeline facilities that we believe meet
the traditional tests the FERC has used to establish a pipeline's status as a
gatherer not subject to FERC jurisdiction under the NGA. State regulation of
gathering facilities generally includes various safety, environmental, and in
some circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation.

ENVIRONMENTAL REGULATIONS

General

Our activities are subject to existing federal, state and local laws and
regulations governing environmental quality and pollution control. Our
activities with respect to exploration, drilling and production from wells,
natural gas facilities, including the operation and construction of pipelines,
plants and other facilities for transporting, processing, treating or storing
gas and other products, are subject to stringent environmental regulation by
state and federal authorities including the Environmental Protection Agency
("EPA"). Risks are inherent in oil and gas exploration and production
operations, and we can give no assurance that significant costs and liabilities
will not be incurred in connection with environmental compliance issues. Neither
can we predict what effect future regulation or legislation, enforcement
policies issued thereunder, and claims for damages to property, employees, other
persons and the environment resulting from our operations could have.

Solid and Hazardous Waste

Mission currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and gas. Although we utilized operating and waste disposal
practices that were standard in the industry at the time, hydrocarbons or other
solid wastes may have been disposed or released on or under the properties we
currently own or lease or on or under properties that we once owned or leased.
In addition, many of these properties are or have been operated by third parties
over whom we had no control as to their treatment of hydrocarbons or other solid
wastes and the manner in which such substances may have been disposed or
released. State and federal laws applicable to oil and gas wastes and properties
have gradually become stricter over time. Under recent laws, we could be
required to remove or remediate previously disposed wastes (including wastes
disposed or released by prior owners or operators) or property contamination
(including groundwater contamination by prior owners or operators) or to perform
remedial plugging operations to prevent future contamination.

Mission generates wastes, including hazardous wastes, that are subject to
the federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA and various state agencies have limited the disposal options
for certain wastes, including wastes designated as hazardous under RCRA and
state analogs ("Hazardous Waste"). Furthermore, it is possible that certain
wastes generated by our oil and gas operations that are currently exempt from
treatment as Hazardous Waste may in the future be designated as Hazardous Waste
under RCRA or other applicable statutes, and therefore be subject to more
rigorous and costly operating and disposal requirements.

12

Superfund

The federal Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and
several liability for costs of investigation and remediation and for natural
resource damages, without regard to fault or the legality of the original
conduct, on potentially responsible parties ("PRPs") with respect to the release
into the environment of substances designated under CERCLA as hazardous
substances ("Hazardous Substances"). PRPs include the current and certain past
owners and operators of a facility where there is or has been a release or
threat of release of a Hazardous Substance and persons who disposed of or
arranged for the disposal of the Hazardous Substances released at the site.
CERCLA also authorizes the EPA and, in some cases, third parties, to take
actions in response to threats to the public health or the environment and to
seek to recover from the PRPs the costs of such action. Although CERCLA
generally exempts "petroleum" from the definition of Hazardous Substances, in
the course of its operations, Mission has generated and will generate wastes
that may be a CERCLA Hazardous Substance. We may also own or operate sites on
which Hazardous Substances have been released. Mission may be responsible under
CERCLA for all or part of the costs of investigation, remediation, and natural
resource damages at sites where Hazardous Substances have been released. We have
not been named a PRP under CERCLA nor do we know of any prior owners or
operators of our properties that are named as PRPs related to their ownership or
operation of such properties.

Clean Water Act

The Clean Water Act ("CWA") imposes restrictions and strict controls
regarding the discharge of wastes, including produced waters and other oil and
natural gas wastes, into waters of the United States, a term broadly defined and
including wetlands. These controls have become more stringent over the years,
and it is probable that additional restrictions will be imposed in the future.
Permits must be obtained to discharge pollutants into waters of the United
States. The CWA and OPA require facilities that store or otherwise handle oil in
excess of specified quantities to prepare and implement spill prevention,
control and countermeasure plans and facility response plans relating to
possible discharges of oil to surface waters. The CWA provides for civil,
criminal and administrative penalties for violations, including unauthorized
discharges of pollutants and of oil or hazardous substances. State laws
governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In the event of an unauthorized discharge of wastes, Mission may be liable for
penalties and costs.

Oil Pollution Act

The Oil Pollution Act of 1990 ("OPA"), which amends and augments oil spill
provisions of CWA, imposes certain duties and liabilities on certain
"responsible parties" related to the prevention of oil spills and damages
resulting from such spills in United States waters and adjoining shorelines. A
"responsible party" includes the owner or operator of a facility or vessel that
is a source of an oil discharge or poses the substantial threat of discharge, or
the lessee or permittee of the area in which a discharging facility covered by
OPA is located. OPA assigns joint and several liability, without regard to
fault, to each responsible party for oil removal costs and a variety of public
and private damages. Few defenses exist to the liability imposed by OPA. In the
event of an oil discharge or substantial threat of discharge, Mission may be
liable for costs and damages.

The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in the event of a
potential spill. The OPA requires owners and operators of offshore facilities
that have a worst case oil spill potential of more than 1,000 barrels to
demonstrate financial responsibility in amounts ranging from $10 million in
specified state waters and $35 million in federal OCS waters, with higher
amounts, up to $150 million based upon worst case oil spill discharge volume
calculations. We believe that we currently have established adequate proof of
financial responsibility for our offshore facilities.

13

Air Emissions

Mission's operations are subject to local, state and federal regulations
for the control of emissions of air pollution. Federal and State laws require
new and modified sources of air pollutants to obtain permits prior to commencing
construction. Major sources of air pollutants are subject to more stringent
requirements including additional permits. Particularly stringent requirements
may be imposed on major sources located in non-attainment areas designated as
not meeting National Ambient Air Quality Standards established by the EPA.
Administrative enforcement actions for failure to comply strictly with air
pollution regulations or permits are generally resolved by payment of monetary
fines and correction of any identified deficiencies. Alternatively, regulatory
agencies may bring lawsuits for civil or criminal penalties or require us to
forego construction, modification or operation of certain air emission sources.

Coastal Coordination

There are various federal and state programs that regulate the conservation
and development of coastal resources. The federal Coastal Zone Management Act
("CZMA") was passed in 1972 to preserve and, where possible, restore the natural
resources of the Nation's coastal zone. The CZMA provides for federal grants for
state management programs that regulate land use, water use and coastal
development.

In Texas, the Texas Legislature enacted the Coastal Coordination Act in
1991 ("CCA"). The CCA provides for the coordination among local and state
authorities to protect coastal resources through regulating land use, water, and
coastal development. The act establishes the Texas Coastal Management Program
("CMP"). The CMP is limited to the nineteen counties that border the Gulf of
Mexico and its tidal bays. The act provides for the review of state and federal
agency rules and agency actions for consistency with the goals and policies of
the Coastal Management Plan. This review may impact agency permitting and review
activities and add an additional layer of review to certain activities that we
undertake.

In Louisiana, state legislation enacted in 1978 established the Louisiana
Coastal Zone Management Program ("LCZMP") to protect, develop and, where
feasible, restore and enhance coastal resources of the state. Under the LCZMP,
coastal use permits are required for certain activities in the coastal zone,
even if the activity only partially infringes on the coastal zone. The Coastal
Management Division of Louisiana's Department of Natural Resources administers
the coastal use permit program which applies in coastal areas of 18 of
Louisiana's 64 parishes. Activities requiring such a permit include, among other
things, projects involving use of state lands and water bottoms, dredge or fill
activities that intersect with more than one body of water, mineral activities,
including the exploration and production of oil and gas, and pipelines for the
gathering, transportation or transmission of oil, gas and other minerals.
General permits, which entail a reduced administrative burden, are available for
a number of routine oil and gas activities. The LCZMP and its requirement to
obtain coastal use permits may result in additional permitting requirements and
associated time constraints for our projects.

OSHA and other Regulations

We are subject to the requirements of the federal Occupational Safety and
Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication
standard, the Environmental Protection Agency community right-to-know
regulations under Title III of CERCLA and similar state statutes require Mission
to organize and/or disclose information about hazardous materials used or
produced in its operations. We believe that we are in substantial compliance
with the applicable requirements.

In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
OCS. Specific design and operational standards may apply to Outer Continental
Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease
conditions or regulations issued pursuant to the OCSLA can result in substantial
civil and criminal penalties, as well as potential court injunctions curtailing
operations and the cancellation of leases. Such enforcement liabilities can
result from either governmental or private prosecution.

14

TITLE TO OUR PROPERTIES

When we acquire developed properties, we conduct a title investigation.
However, when we acquire undeveloped properties, as is common industry practice,
we usually conduct a title review of local mineral records. We do conduct title
investigations and often obtain a title opinion before we begin drilling
operations. We believe that the methods we use for investigating title prior to
acquiring any property are consistent with standards generally accepted in the
oil and gas industry and that our practices are adequately designed to enable us
to acquire good title to properties. However, some title risks cannot be
avoided, despite the use of accepted practices.

Our properties are typically subject, in one degree or another, to one or
more of the following:

- royalties;

- overriding royalties;

- a variety of contractual obligations (including, in some cases,
development obligations) arising under operating agreements, farmout
agreements, production sales contracts and other agreements that may
affect the properties or their titles;

- back-ins and reversionary interests;

- liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing obligations to unpaid suppliers
and contractors and contractual liens under operating agreements;

- pooling, unitization and communitization agreements, declarations and
orders; and

- easements, restrictions, rights-of-way and other matters that commonly
affect oil and gas producing property.

To the extent that such burdens and obligations affect our rights to
production revenues, they have been taken into account in calculating net
revenue interests and in estimating the size and value of our proved reserves.
We believe that the burdens and obligations affecting our properties are
conventional in the industry for the kind of properties that we own. Up to 90%
of our properties are pledged as collateral under our credit facility.

OUR EMPLOYEES

At December 31, 2003, Mission had 85 full time employees. In addition to
the services of our full time employees, we utilize the services of independent
contractors to perform certain services. We believe that our relationships with
our employees are satisfactory. None of our employees is covered by a collective
bargaining agreement.

In the beginning of 2003, we were party to a Master Service Agreement
("MSA") dated October 1, 1999, and two service contracts under the terms of
which Torch Energy Advisors, Inc. ("Torch") operated our oil and gas properties
and marketed our oil and gas production. We terminated the service contracts
effective February 1, 2003 and April 1, 2003, respectively. We hired additional
qualified employees, including many of the operations staff from Torch, to
handle those functions. The MSA was terminated on April 1, 2003 because all
service contracts had terminated as of that date.

OUR FACILITIES

Our corporate office occupies approximately 29,000 square feet of leased
office space at 1331 Lamar, Suite 1455, Houston, Texas 77010. We also have
leased offices in Giddings, Texas and Lafayette, Louisiana from which our
employees supervise local oil and gas operations.

15

OUR AVAILABLE INFORMATION

Mission's Internet website can be found at www.mrcorp.com. Mission makes
available free of charge, or through the "Investor Relations" section of our
Internet website at www.mrcorp.com, access to our annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to
those reports filed pursuant to Section 13(a) of 15(d) of the Securities
Exchange Act of 1934, as amended, as soon as reasonable practicable after such
material is filed or furnished to the Securities and Exchange Commission.

RISK FACTORS

RISKS RELATED TO FINANCING OUR BUSINESS

If we are not able to fund our planned capital expenditures, our cash flow
from operations will decrease.

We make, and will need to continue to make, substantial capital
expenditures for the development, exploration, acquisition and production of oil
and gas reserves. Our capital expenditures were $35.4 million, $21.4 million,
and $72.2 million for the years ended December 31, 2003, 2002 and 2001,
respectively. Historically, we have financed these expenditures primarily with
cash flow from operations, the issuance of bonds or bank credit facility
borrowings, the issuance of our common stock, or the sale of oil and gas
properties. Our current primary sources of liquidity are cash flow from
operations, credit facility borrowings, and sales of oil and gas properties. We
have budgeted total capital expenditures in 2004 of $32.0 to $34.0 million,
however, we intend to increase or decrease this amount depending upon cash flow
generated by operations. Natural gas and oil prices, the timing of our drilling
program and drilling results have a significant impact on the cash flows
available for capital expenditures and our ability to borrow and raise
additional capital. Lower prices and/or lower production may decrease revenues
and cash flows, thus reducing the amount of financial resources available to
meet our capital requirements.

We believe that cash flows from operating activities combined with our
ability to control the timing of substantially all of our future exploration and
development requirements will provide us with the flexibility and liquidity to
meet our planned capital requirements for 2004. If revenues or our borrowing
base decrease for any of the reasons discussed above, we may have limited
ability to expend the capital necessary to undertake our 2004 exploration and
development program. We cannot assure you that additional debt or equity
financing or cash generated by operations or oil and gas property sales will be
available to meet these requirements.

We have a highly leveraged capital structure, which limits our financial
flexibility.

We have a highly leveraged capital structure due to our outstanding 10 7/8%
senior subordinated notes due 2007 and our $80.0 million term loan facility.
Although we reduced the outstanding balance of our 10 7/8% subordinated notes
due 2007 to $117.4 million in 2003, our capital structure remains highly
leveraged, which limits our financial flexibility. Our level of indebtedness has
several important effects on our future operations, including:

- a substantial portion of our cash flow from operations, approximately $22
million in 2004, must be dedicated to the payment of interest on our
indebtedness and will not be available for other purposes;

- covenants contained in our debt obligations, including those in our $80.0
million term loan facility, require us to meet certain financial tests,
and other restrictions limit our ability to borrow additional funds or
dispose of assets and may affect our flexibility in planning for, and
reacting to, changes in our business, including possible acquisition
activities; and

- our ability to obtain financing in the future for working capital,
capital expenditures, acquisitions, general corporate purposes or other
purposes may be impaired.

Our ability to meet our debt service obligations and to reduce our total
indebtedness will be dependent upon future performance, which will be subject to
general economic conditions and to financial,

16

business and other factors affecting our operations, many of which are beyond
our control. We cannot assure you that our future performance will not be
adversely affected by such economic conditions and financial, business and other
factors. We intend to take additional actions in 2004 to improve our financial
condition. Among the alternatives that we may consider are

- a refinancing of the remaining 10 7/8% subordinated notes;

- a new credit facility;

- a merger with or an acquisition by another company;

- the acquisition by Mission of another company or assets;

- other secured and unsecured debt financings; and

- the issuance of equity securities or other debt securities for cash or
properties or in exchange for the notes.

Some of these alternatives would require approval of our stockholders, and
all of them will require the approval of other parties to the transaction. We
cannot assure you that we will be successful in completing any of these possible
transactions.

Hedging production may limit potential gains from increases in commodity
prices or result in losses.

We enter into hedging arrangements from time to time to reduce our exposure
to fluctuations in natural gas and oil prices and to achieve more predictable
cash flow. These financial arrangements take the form of cashless collars or
swap contracts and are placed with major trading counter parties we believe
represent minimum credit risks. We cannot assure you that these trading counter
parties will not become credit risks in the future. Hedging arrangements expose
us to risks in some circumstances, including situations when the other party to
the hedging contract defaults on its contract obligations or there is a change
in the expected differential between the underlying price in the hedging
agreement and actual prices received. These hedging arrangements may limit the
benefit we could receive from increases in the prices for natural gas and oil.
We cannot assure you that the hedging transactions we have entered into, or will
enter into, will adequately protect us from fluctuations in natural gas and oil
prices.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

We may be unable to acquire or develop additional reserves.

As is generally the case in the oil and natural gas industry, our success
depends upon our ability to find, develop or acquire additional oil and natural
gas reserves that are profitable to produce. Factors that may hinder our ability
to acquire additional oil and natural gas reserves include competition, access
to capital, prevailing oil and natural gas prices and the number of properties
for sale. If we are unable to conduct successful development activities or
acquire properties containing proved reserves, our total proved reserves will
generally decline as a result of production. Also, our production will generally
decline. If our reserves and production decline then the amount we are able to
borrow under our credit facility will also decline. We cannot assure you that we
will be able to locate additional reserves, that we will drill economically
productive wells or that we will acquire properties containing proved reserves.

17

Market uncertainty and a variety of additional factors beyond our control can
create large price fluctuations in response to relatively minor changes in the
supply and demand for oil and natural gas, which could result in low commodity
prices.

Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include:

- weather conditions in the United States;

- the condition of the United States economy;

- the actions of the Organization of Petroleum Exporting Countries;

- domestic and foreign governmental regulation;

- political stability in the Middle East and elsewhere;

- the foreign supply of oil and gas;

- the price of foreign imports; and

- the availability of alternate fuel sources.

Any substantial and extended decline in the price of oil or gas would have
an adverse effect on the carrying value of our proved reserves, our borrowing
capacity, our ability to obtain additional capital, and our revenues,
profitability and cash flows. Lower prices may also reduce the amount of oil and
natural gas that we can produce economically and require us to record ceiling
test write-downs.

Volatile oil and gas prices make it difficult to estimate the value of
producing properties in connection with acquisitions and often cause disruption
in the market for oil and gas producing properties as buyers and sellers have
difficulty agreeing on transaction values. Price volatility also makes it
difficult to budget for and project the return on acquisitions and exploitation,
development and exploration projects. To attempt to reduce our price risk, we
periodically enter into hedging transactions with respect to a portion of our
expected future production. We cannot assure you that such transactions will
reduce the risk or minimize the effect of any decline in oil or natural gas
prices.

We may not be able to market all or obtain favorable prices for the oil or gas
we produce.

Our ability to market oil and gas from our wells depends upon numerous
domestic and international factors beyond our control, including

- the extent of domestic production and imports of oil and gas;

- the proximity of gas production to gas pipelines;

- the availability of capacity in such pipelines;

- the demand for oil and gas by utilities and other end users;

- the availability of alternate fuel sources;

- the effects of inclement weather;

- state, federal and international regulation of oil and gas production;
and

- federal regulation of gas sold or transported in interstate commerce.

We cannot assure you that we will be able to market all of the oil or gas
we produce or that we can obtain favorable prices for the oil and gas we
produce.

18

You should not place undue reliance on reserve information because reserve
information represents estimates.

This document contains estimates of our oil and gas reserves and the future
net cash flows attributable to those reserves. There are numerous uncertainties
inherent in estimating quantities of proved reserves and cash flows attributable
to such reserves, including factors beyond our control and the control of
reserve engineers. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. The accuracy of an estimate of quantities of reserves, or of cash flows
attributable to such reserves, is a function of

- the available data;

- assumptions regarding future oil and gas prices and expenditures for
future development and exploitation activities; and

- engineering and geological interpretation and judgment.

Additionally, reserves and future cash flows may be subject to material
downward or upward revisions based upon production history, development and
exploitation activities and prices of oil and gas. Actual future production,
revenue, taxes, development expenditures, operating expenses, quantities of
recoverable reserves and the value of cash flows from such reserves may vary
significantly from the assumptions and estimates in this document. In
calculating reserves on a gas equivalent basis, oil was converted to gas
equivalent at the ratio of six MCF of gas to one BBL of oil. While this ratio
approximates the energy equivalency of gas to oil on a BTU basis, it may not
represent the relative prices received by us on the sale of our oil and gas
production.

You should not assume that the present value of future net revenues
referred to in this document and the information incorporated by reference is
the current market value of our estimated oil and natural gas reserves. In
accordance with Securities and Exchange Commission requirements, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate. Actual future prices and costs
may be materially higher or lower than the prices and costs as of the date of
the estimate. Any changes in consumption by natural gas purchasers or in
governmental regulations or taxation may also affect actual future net cash
flows. The timing of both the production and the expenses from the development
and production of oil and natural gas properties will affect the timing of
actual future net cash flows from proved reserves and their present value. In
addition, the 10% discount factor, which is required by the Securities and
Exchange Commission to be used in calculating discounted future net cash flows
for reporting purposes, is not necessarily the most accurate discount factor.
The effective interest rate at various times and the risks associated with our
operations or the oil and natural gas industry in general will affect the
accuracy of the 10% discount factor.

Lower oil and natural gas prices may cause us to record ceiling test
write-downs.

We use the full cost method of accounting to account for our oil and
natural gas operations. Accordingly, we capitalize the cost to acquire, explore
for and develop oil and natural gas properties. Under full cost accounting
rules, the net capitalized costs of oil and natural gas properties may not
exceed a "ceiling limit" which is based upon the present value of estimated
future net cash flows from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. If net capitalized costs of
oil and natural gas properties exceed the ceiling limit, we must charge the
amount of the excess to earnings. This is called a "ceiling test write-down."
This charge does not impact cash flow from operating activities, but does reduce
our stockholders' equity. The risk that we will be required to write down the
carrying value of oil and natural gas properties increases when oil and natural
gas prices are low or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves.

19

Competition in our industry is intense, and many of our competitors have
greater financial, technological and other resources than we have.

The oil and natural gas industry is highly competitive. We encounter strong
competition from other independent operators and from major oil companies in
acquiring properties, contracting for drilling equipment and securing trained
personnel. Many of these competitors may be able to pay more for desirable
leases, or evaluate, bid for and purchase a greater number of properties or
prospects than our financial or personnel resources will permit. In the past,
the oil and natural gas industry has experienced shortages of drilling rigs,
equipment, pipe and personnel, which has delayed development drilling and other
exploration activities and has caused significant price increases. In the event
of such shortages, larger competitors may have an advantage in obtaining
drilling rigs and equipment. We are unable to predict when, or if, such
shortages may again occur or how they would affect our exploration and
development program. Competition is also strong for attractive oil and natural
gas producing properties, undeveloped leases and drilling rights, and we cannot
assure you that we will be able to compete successfully. Many large oil
companies have been actively marketing some of their existing producing
properties for sale to independent producers. We cannot assure you that we will
be successful in acquiring any of these properties.

We may have claims asserted against us to plug and abandon wells and restore
the surface.

In most instances, oil and gas lessees are required to plug and abandon
wells that have no further utility and to restore the surface. We are often
required to obtain bonds to secure these obligations. In instances where we
purchase or sell oil and gas properties, the parties to the transaction
routinely include an agreement as to who will be responsible for plugging and
abandoning any wells on the property and for restoring the surface. In those
cases, we may be required to obtain new bonds or may release old bonds regarding
our plugging and abandonment exposure based on the terms of the purchase and
sale agreement. However, if a subsequent owner or party to the purchase and sale
agreement defaults on its obligations to plug and abandon a well or restore the
surface and otherwise fails to obtain a bond to secure the obligation, the
landowner or in some cases the applicable state or federal regulatory authority,
may assert that we are obligated to plug the well as a prior owner of the
property. In other instances, we may receive a demand as a current owner of the
property to plug and abandon certain wells in the field and to restore the
surface although we are still actively developing the field.

Mission has been notified of such claims from certain parties and
landowners and from the State of Louisiana. For the year 2003 we have recognized
costs of approximately $252,000 for the abandonment and cleanup of the Bayou
Ferblanc field and approximately $379,000 for the proposed settlement of
abandonment issues at the West Lake Ponchartrain field. Approximately $161,000
in costs related to Bayou Ferblanc were recognized in 2002. At this time, it is
not possible to determine the amount of potential exposure that we may have for
any other claims. Although there can be no assurances, we do not presently
believe these claims would have a material adverse effect on our financial
condition or operations.

In 1993 and 1996 we entered into agreements with surety companies and, at
that time, affiliated companies Torch and Nuevo Energy Company ("Nuevo") whereby
the surety companies agreed to issue such bonds to Mission, Torch and Nuevo. As
part of these agreements, Mission, Torch, and Nuevo agreed to be jointly and
severally liable to the surety company for any liabilities arising under any
bonds issued to Mission, Torch and Nuevo. The amount of bonds presently issued
to Torch and Nuevo pursuant to these agreements is approximately $0.4 million
and $34.8 million, respectively. We have notified the sureties that we will not
be responsible for any new bonds issued to Torch or Nuevo. However, the sureties
are permitted under these agreements to seek reimbursement from us, as well as
from Torch and Nuevo, if the surety makes any payments under the bonds
previously issued to Torch and Nuevo.

20

Compliance with environmental and other government regulations is costly and
could negatively impact production.

Our operations are subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. For a discussion of material regulations applicable to
us, see "Regulation -- Federal Regulations," "-- State Regulations" and
"-- Environmental Regulations." These laws and regulations:

- require the acquisition of a permit before drilling commences;

- restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;

- limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas;

- require remedial measures to mitigate pollution from former operations,
such as plugging abandoned wells; and

- impose substantial liabilities for pollution resulting from our
operations.

The recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. The enactment of stricter legislation or the
adoption of stricter regulations could have a significant impact on our
operating costs, as well as on the oil and gas industry in general.

The Oil Pollution Act of 1990 imposes a variety of regulations on
"responsible parties" related to the prevention of oil spills. The
implementation of new, or the modification of existing, environmental laws or
regulations, including regulations promulgated pursuant to the Oil Pollution Act
of 1990, could have a material adverse impact on us.

RISKS RELATING TO OUR ONGOING OPERATIONS

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key
management and technical personnel, including, but not limited to, Robert L.
Cavnar, our Chairman, Chief Executive Officer and President, Richard W.
Piacenti, our Executive Vice President and Chief Financial Officer, John L.
Eells, our Senior Vice President -- Exploration and Geoscience, Joseph G.
Nicknish, our Senior Vice President -- Operations and Engineering, and Marshall
L. Munsell, our Senior Vice President -- Land and Land Administration. We cannot
assure you that such individuals will remain with us for the immediate or
foreseeable future. The unexpected loss of the services of one or more of these
individuals could have a detrimental effect on our operations.

The oil and gas business involves many operating risks that can cause
substantial losses.

Our operations are subject to risks inherent in the oil and gas industry,
such as

- unexpected drilling conditions, such as blowouts, cratering and
explosions;

- uncontrollable flows of oil, gas or well fluids;

- equipment failures, fires, earthquakes, hurricanes or accidents; and

- pollution and other environmental risks.

These risks could result in substantial losses to us due to injury and loss
of life, severe damage to and destruction of property and equipment, pollution
and other environmental damage and suspension of operations. Moreover, a portion
of our operations are offshore and therefore are subject to a variety of
operating risks that occur in the marine environment, such as hurricanes or
other adverse weather conditions, and to more extensive governmental regulation,
including regulations that may, in certain

21

circumstances, impose strict liability for pollution damage, and to interruption
or termination of operations by governmental authorities based on environmental
or other considerations.

We cannot control the development of the properties we own but do not operate.

As of December 31, 2003, we do not operate wells that represent
approximately 65% of the present value of estimated future net revenues of our
proved reserves. As a result, the success and timing of our drilling and
development activities on those properties depend upon a number of factors
outside our control, including

- the timing and amount of capital expenditures;

- the operators' expertise and financial resources;

- the approval of other participants in drilling wells; and

- the selection of suitable technology.

If drilling and development activities are not conducted on these
properties, we may not be able to increase our production or offset normal
production declines.

Losses and liabilities from uninsured or underinsured drilling and operating
activities could have a material adverse effect on our financial condition and
operations.

Our operations could result in a liability for personal injuries, property
damage, oil spills, discharge of hazardous materials, remediation and clean-up
costs and other environmental damages. We could also be liable for environmental
damages caused by previous property owners. As a result, substantial liabilities
to third parties or governmental entities may be incurred, the payment of which
could have a material adverse effect on our financial condition and results of
operations. We maintain insurance coverage for our operations, including limited
coverage for sudden environmental damages, but do not believe that insurance
coverage for all environmental damages that occur over time is available at a
reasonable cost. Moreover, we do not believe that insurance coverage for the
full potential liability that could be caused by sudden environmental damages is
available at a reasonable cost. Accordingly, we may be subject to liability or
the loss of substantial portions of our properties in the event of certain
environmental damages.

RISKS RELATED TO OUR COMMON STOCK OUTSTANDING

Our stock price is volatile, which could cause you to lose part or all of your
investment.

The stock market has from time to time experienced significant price and
volume fluctuations that may be unrelated to the operating performance of
particular companies. In particular, the market price of our common stock, like
that of the securities of other energy companies, has been and may be highly
volatile. Factors such as announcements concerning changes in prices of oil and
natural gas, the success of our exploration and development drilling program,
the availability of capital, and economic and other external factors, as well as
period-to-period fluctuations and financial results, may have a significant
effect on the market price of our common stock.

The lack of trading could adversely affect the prevailing market for our
common stock.

Historically, there has been limited trading volume with respect to our
common stock. In addition, we cannot assure you that there will continue to be a
trading market or that any securities research analysts will provide research
coverage with respect to our common stock. It is possible that such factors will
adversely affect the market for our common stock.

22

Issuance of shares in connection with financing transactions or under stock
incentive plans will dilute current stockholders.

If we raise additional funds by issuing shares of common stock, or
securities convertible into or exchangeable or exercisable for common stock, or
if we enter into additional arrangements to issue common stock in exchange for
outstanding debt obligations, further dilution to our existing stockholders will
result. New investors could also have rights superior to existing stockholders.
Pursuant to our stock incentive plans, our management is authorized to grant
stock awards to our employees, directors and consultants. You will incur
dilution upon exercise or vesting of any outstanding stock awards.

The number of shares of our common stock eligible for future sale could
adversely affect the market price of our stock.

The issuance of a significant number of shares of common stock upon the
exercise of stock options, or the availability for sale or sale of a substantial
number of the shares of common stock eligible for future sale under effective
registration statements, Rule 144 or otherwise, could adversely affect the
market price of the common stock. We have reserved approximately 4.7 million
shares of common stock for issuance under outstanding options. These shares of
common stock are registered for resale on currently effective registration
statements. We registered the resale of 4.5 million shares of common stock that
were issued in exchange for $10 million of our 10 7/8% senior subordinated notes
due 2007. We are also obligated to register the resale of the 6.25 million
shares of common stock issued in exchange for $15 million of our notes in
February 2004.

We have not and do not expect in the near future to pay dividends.

We have never declared or paid any cash dividends on our common stock and
have no intention to do so in the near future. The restrictions on our present
or future ability to pay dividends are included in the provisions of the
Delaware General Corporation Law and in certain restrictive provisions in the
indentures executed in connection with our 10 7/8% senior subordinated notes due
2007. In addition, our credit facility contains provisions that may have the
effect of limiting or prohibiting the payment of dividends.

Our certificate of incorporation, bylaws, rights plan and Delaware law have
provisions that discourage corporate takeovers and could prevent stockholders
from realizing a premium on their investment.

Certain provisions of our certificate of incorporation, bylaws and rights
plan and the provisions of the Delaware General Corporation Law may encourage
persons considering unsolicited tender offers or other unilateral takeover
proposals to negotiate with our board of directors rather than pursue
non-negotiated takeover attempts. Our certificate of incorporation authorizes
our board of directors to issue preferred stock without stockholder approval and
to set the rights, preferences and other designations, including voting rights
of those shares, as the board may determine. Additional provisions include
restrictions on business combinations and on stockholder action by written
consent. We are also subject to Section 203 of the Delaware General Corporation
Law, which generally prohibits a Delaware corporation from engaging in any of a
broad range of business combinations with an interested stockholder for a period
of three years following the date on which the stockholder became an interested
stockholder. These provisions, alone or in combination with each other and with
the rights plan described below, may discourage transactions involving actual or
potential changes of control, including transactions that otherwise could
involve payment of a premium over prevailing market prices to stockholders for
their common stock.

In September 1997, our board of directors adopted a rights plan, pursuant
to which uncertificated stock purchase rights were distributed to our
stockholders at a rate of one right for each share of common stock held of
record as of September 26, 1997. The rights plan is designed to enhance the
board's ability to prevent an acquirer from depriving stockholders of the
long-term value of their investment and to protect stockholders against attempts
to acquire us by means of unfair or abusive takeover tactics. However, the
existence of the rights plan may impede a takeover not supported by our board,
including a

23

takeover that may be desired by a majority of our stockholders or involving a
premium over the prevailing stock price.

ITEM 3. LEGAL PROCEEDINGS

Mission is involved in litigation relating to claims arising of its
operations in the normal course of business, including workmen's compensation
claims, tort claims and contractual disputes. Some of the existing known claims
against us are covered by insurance subject to the limits of such policies and
the payment of deductible amounts by us. Management believes that the ultimate
disposition of all uninsured or unindemnified matters resulting from existing
litigation will not have a material adverse effect on Mission's business or
financial position.

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

None.

PART II

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

Mission's common stock is traded on The Nasdaq National Market (Symbol:
MSSN).

The following table sets forth the range of the high and low sales prices,
as reported by Nasdaq for our common stock for the periods indicated.

We have not paid dividends on our common stock and do not anticipate paying
cash dividends in the immediate future as we contemplate that our cash flows
will be used for continued growth of our operations. In addition, certain
covenants contained in our financing arrangements restrict the payment of
dividends (see Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Financing Activities and Note 8 of the Notes to
Consolidated Financial Statements). There were approximately 1,310 stockholders
of record as of February 18, 2004.

On December 17, 2003, we entered into a purchase and sale agreement with
FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income
Series providing for the issuance by us of 4.5 million shares of our common
stock in exchange for the surrender by the Franklin entities of $10.0 million
aggregate principal amount of our 10 7/8% senior subordinated notes due 2007.
Accrued interest on the notes to the date of the agreement will be paid on April
1, 2004, the regularly scheduled interest payment date for the notes, or upon
the occurrence of certain other events. The shares of common stock issued in the
transaction were exempt from registration pursuant to Section 3(a)(9) of the
Securities Act of 1933, as amended, as they were exchanged with our existing
security holders exclusively and no commission or remuneration was paid or given
directly or indirectly for the exchange.

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ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data with respect to Mission should be
read in conjunction with the Consolidated Financial Statements and supplementary
information included in Item 8 (amounts in thousands, except per share data).

25

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

Mission is an independent oil and gas exploration and production company.
We drill for, acquire, develop and produce natural gas and crude oil. Our
property portfolio is comprised of long-lived, low-risk assets, like those in
the Permian Basin, and multi-reservoir, high-productivity assets found along the
Gulf Coast and in the Gulf of Mexico. Our operational focus remains on
efficient, well managed upstream natural gas and crude oil exploration and
production. We will continue to pursue complementary acquisitions when the
appropriate opportunities present themselves. Mission's results of operations
for the year 2003 included the following financial and operational highlights.

- Reduced long-term debt by $27.9 million and annual interest expense by $2
million

- Reduced operating expenses per MCFE from $1.42 in the fourth quarter of
2002 to $1.24 in the fourth quarter of 2003.

- Established a new revolving credit facility, making available $12.5
million for short-term borrowings.

- Sold several high-cost oil properties, making available approximately $25
million for re-investment in gas properties.

- Drilled 3 successful exploratory and 39 successful developmental wells
that increased reserves enough to fully replace 2003 production.

- Moved in-house previously outsourced functions of operations, marketing,
accounting, treasury, land administration, human resources and risk
management. As a result of this infrastructure shift, we were able to
achieve greater levels of efficiency and responsiveness.

- Completed building our exploration team of experienced geophysicists and
geologists with significant expertise in the industry and our core areas.

- Hedged approximately 75% of 2004 proved developed producing reserves at a
weighted average floor price of $24.86 per BBL and $4.53 per MMBTU, with
additional hedges on 2005 production.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002

Net Income/Loss -- Net income for the year ended December 31, 2003 was $2.4
million, or $0.10 per share on a diluted basis, while the net loss for the year
ended December 31, 2002 was $38.5 million, or $1.63 per share on a diluted
basis. In 2003, our purchase and retirement of $107.6 million principal amount
of senior subordinated notes generated a $23.5 million gain, $15.3 million net
of tax, on the extinguishment of debt. See "Financial Condition -- Financing"
section below for additional information about the debt retirement transactions.
In 2002, we recognized a $16.7 million goodwill impairment.

26

Oil and Gas Revenues -- Oil and gas revenues were $99.3 million in the year
ended December 31, 2003, compared to $112.9 million for the respective period in
2002. The table below details the components of oil and gas revenues and their
respective changes between the periods (dollar amounts in millions, except
prices):

The property sales in late 2002 plus the additional sales in the fourth
quarter of 2003 are the primary cause of the oil and gas production declines.
Gas production increases from drilling, recompletions and workovers done at
South Marsh Island, North Leroy and West Lake Verret partially offset the
production declines. Because these projects were completed late in 2003, their
impact in 2003 is small, but we expect continued production from these projects
to benefit our 2004 results.

The favorable impact of high commodity prices offset most of the production
decreases. Several factors, including instability in the Middle East and a cold
winter, contributed to the commodity price increases.

27

Costs of Oil and Gas Production -- In addition to analyzing gross changes
in costs, management finds it useful to look at some costs on a per unit basis.
The table below details our costs of oil and gas production by cost type both in
dollars incurred and, where useful, in dollars per MCFE, and their respective
changes between the periods (dollars in millions, except per unit amounts).

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

(1) Transportation costs and production taxes relate to specific production,
therefore analysis of such costs per unit of total production is not useful.

Total lease operating expenses for the year 2003 decreased 24.3% from 2002
levels, but increased 9.2% on a per MCFE basis. Production declines contributed
to the per MCFE cost increase. In gross dollars, the most significant cost
reductions related to the sale of properties at auction in November 2002, the
sale of the Pt. Pedernales field in March 2003, and the sales of the East Texas,
East Cameron and Raccoon Bend fields in the fourth quarter of 2003. The East
Texas field and the Raccoon Bend field consisted of high per MCFE cost oil
properties. We expect the impact of the fourth quarter sales to be evident on a
per MCFE basis beginning the first quarter of 2004. Combined with the addition
of the low cost per MCFE production from the newly acquired Jalmat field, we
expect first quarter 2004 operating expenses to be between $1.25 and $1.35 per
MCFE.

Production taxes, depending upon the jurisdiction, are calculated using a
percentage of revenue or a per-unit of production rate. They vary with both
price and production levels.

Property taxes are assessed based upon property value calculated at the
beginning of each year. Our reduced number of properties coupled with reductions
in the assessed values of our remaining properties caused the property tax
reduction in 2003. Assessed values are based upon beginning of the year reserves
and the previous year's average realized price. Because our average realized
prices in 2003 were considerably higher than in 2002, we expect property taxes
to increase in 2004.

Because our depreciation, depletion and amortization ("DD&A") is calculated
on the units of production method, the production decrease resulting from normal
production declines and from property sales is driving the overall decline in
DD&A expense. The increase in DD&A on a per MCFE basis reflected the impact of
decreases in reserves due to property sales.

Asset Retirement Obligation Accretion Expense -- Asset retirement
obligation accretion expense is a new category of expense for 2003 that resulted
from the implementation of SFAS No. 143. The liability recorded for our asset
retirement obligation represents the estimate of such costs as of the end of the
reporting period. Each quarter, we are required to increase the liability to
account for the passage of time, resulting in this accretion expense.

Income Taxes -- The federal and state income taxes for the year ended
December 31, 2003 was based upon a 36.5% effective tax rate which represented a
change from the 23.1% effective tax rate of 2002. The 2002 effective rate, as
calculated by dividing income tax benefit by net loss before taxes, was lower
primarily because the impairment of goodwill is not an allowable tax deduction.

28

In December 2003, we have become subject to tax limitations imposed under
Section 382 of the Internal Revenue Code ("382 Limitations"). These limitations
could impact the potential future realization of our tax net operating losses
and other deferred tax assets. Based upon estimates of our recoverable reserves,
future production and related taxable income, management has determined that the
382 Limitations have not currently resulted in our deferred assets being
impaired.

Interest and Other Income -- Interest and other income increased $8.6
million from a net loss of $7.4 million reported for the year 2002 to a net gain
of $1.1 million reported for the year 2003. Gains or losses related to hedge
ineffectiveness, as computed under the requirements of SFAS. No. 133, are the
most significant portion of this line item. A $9.0 million net loss from hedge
ineffectiveness was recorded in 2002 while a net gain of $1.0 million was
recorded in 2003. A $1.7 million gain from the settlement of a royalty
calculation dispute with the MMS was also recorded in 2002.

Interest Expense -- Interest expense decreased 4.5% to $25.6 million for
the year ended December 31, 2003 from $26.8 million for the year ended December
31, 2002. The following table details the components of interest and their
respective changes between the periods (dollar amounts in millions).

The interest rate swap was cancelled in February 2003, limiting our
exposure to interest rate volatility and resulting in a $520,000 gain recognized
in the first quarter of 2003. The March 2003 repurchase of $97.6 million of our
10 7/8% senior subordinated notes and their replacement with an $80.0 million
term loan facility currently bearing interest at 12% has generated interest
savings of approximately $95,000 per month beginning in the second quarter of
2003.

General and Administrative Expenses -- General and administrative expenses
totaled approximately $10.9 million in the year ended December 31, 2003 and
$12.8 million in the year ended December 31, 2002. In 2002, employees of Torch
performed most of our accounting, operating and marketing functions, and we paid
Torch a management fee for these outsourced services. By the end of April 2003
we had terminated all outsourcing contracts with Torch, decreasing our
management fee costs; however, employee costs increased as a result of our
increased staffing to replace Torch employees combined with severance costs
related to the reorganization partially offsetting the management fee savings.

Some costs incurred in 2003 are not expected to be recurring. Our legal
costs were higher as a result of several settled lawsuits and the implementation
of the new corporate governance requirements. We also performed an extensive
review of our lease and well records in connection with the implementation of a
new land system. While many of these costs are not expected to reoccur in 2004,
our general and administrative expenses are anticipated to remain near 2003
levels. Because several of the properties that were sold in 2003 were operated,
our fees recovered on operated properties will be lower in the future. Public
company expenses continue to rise and our salaries and benefits will increase as
we grow the company.

YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001

Net Income/Loss -- Net loss for the year ended December 31, 2002 was $38.5
million, or $1.63 per share on a diluted basis, while the net loss for the year
ended December 31, 2001 was $30.9 million, or $1.54 per share on a diluted
basis. The contributing factors to such losses are discussed below.

29

Oil and Gas Revenues -- Oil and gas revenues were $112.9 million in the
year ended December 31, 2002, compared to $133.2 million for the respective
period in 2001. The table below details the components of oil and gas revenues
and their respective changes between the periods (dollar amounts in millions,
except prices):

The expected decreases in our gas production and our realized gas prices,
excluding hedges, were the primary reasons for our overall decrease in revenues.
Throughout 2002, we sold several oil and gas properties and our production from
our offshore properties declines with the passage of time. Additionally, our
production was shut in both offshore and along the Gulf coast for a few days
during September and October 2002 when hurricanes passed through.

We sold our interests in the Ecuador fields in June 2001. The absence of
revenues from Ecuadorian oil accounts for the majority of the decrease in oil
revenues.

Costs of Oil and Gas Production -- In addition to analyzing gross changes
in costs, management finds it useful to also look at some costs on a per unit
basis. The table below details our costs of oil and gas production by cost type
both in dollars incurred and, where useful, in dollars per MCFE, and their
respective changes between the periods (dollars in millions, except per unit
amounts).

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

(1) Transportation costs and production taxes relate to specific production,
therefore analysis of such costs per unit of total production is not useful.

Total lease operating expenses for the year 2002 decreased 3.6% from 2001
levels, but increased 11.0% on a per MCFE basis. Cost reductions related to
properties sold during 2002 were significant, but

30

the inclusion of a full year of costs from the properties acquired in the 2001
merger with Bargo and the June 2001 South Louisiana acquisition offset that
benefit. Many of those acquired properties were high fixed costs properties so
that declines in production were not matched with declines in expenses, causing
the per MCFE rates to remain high.

Production taxes, depending upon the jurisdiction, are calculated using a
percentage of revenue or a per-unit of production rate. Total production taxes
vary with both price and production levels.

Property taxes are assessed based upon property value calculated at the
beginning of each year. The most significant contribution to increased ad
valorem taxes was the 2001 merger with Bargo and the acquisition of South
Louisiana properties in 2001 because a full year of property taxes was
recognized on those properties in 2002.

Transportation costs represent those expenses incurred to bring production
to sale points such as pipeline fees and gas gathering fees. In 2002, we were
responsible for paying transportation for more of our oil and gas sales. In
2001, Torch purchased a large portion of our production and assumed
responsibility for transportation costs on the gas it purchased from us.

Because our DD&A is calculated on the units of production method, the
decrease in production is driving the overall decline in DD&A expense. The
increase in DD&A on a per MCFE basis reflected the impact of decreases in
reserves as a result of property sales and reserve revisions.

Impairment Expense -- The impairment expense reported in 2002 of $16.7
million was the result of the impairment of goodwill. The impairment expense
reported in 2001 consisted of a $20.8 million full cost ceiling impairment, a
write-off of the $6.2 million long-term receivable and a $914,000 charge for
exploration stage mining activities. Both the goodwill and the full cost ceiling
impairment are discussed in detail under "Critical Accounting Policies". The
long-term receivable represented a production payment receivable due from a
foreign energy company that management determined was uncollectible in the
fourth quarter of 2001.

Income Taxes -- The benefit for federal and state income taxes for the year
ended December 31, 2002 was based upon a 35% statutory tax rate. The effective
rate was reduced to 23.1%, primarily because the impairment of goodwill is not
an allowable tax deduction. Additionally, the $4.3 million valuation allowance
on deferred taxes applicable at December 31, 2001 was increased to $5.3 million
at December 31, 2002, because management determined that the portion of deferred
tax asset relating to state tax losses generated during the period would not be
realized. In assessing the realizability of the deferred tax assets, management
considers whether it is more likely than not that some portion or all of the
deferred tax assets will not be realized. The ultimate realization of deferred
tax assets is dependent upon the generation of future taxable income during the
periods in which those temporary differences become deductible. Based upon the
projection for future state taxable income, management believed it was more
likely than not that we would not realize our deferred tax asset related to
state income taxes.

Loss on Sale of Assets -- The loss on sale of assets of $2.6 million in
2002 was primarily attributable to the post-closing settlement on the sale of
our Ecuadorian interests.

Interest and Other Income -- Interest and other income decreased $11.8
million from a net gain of $4.4 million reported for the year 2001 to a net loss
of $7.4 million reported for the year 2002. Gains or losses related to hedge
ineffectiveness, as computed under the requirements of SFAS. No. 133, were the
most significant portion of this line item. A net gain from hedge
ineffectiveness of $4.8 million was recorded in 2001, while a $9.0 million net
loss from hedge ineffectiveness was recorded in 2002. A $1.7 million gain from
the settlement of a royalty calculation dispute with the MMS was also recorded
in 2002.

31

Interest Expense -- Interest expense increased 13.5% to $26.9 million for
the year ended December 31, 2002 from $23.7 million in the year ended December
31, 2001. The following table details the components of interest and their
respective changes between the periods (dollar amounts in millions).

The $125.0 million of 10 7/8% senior subordinated notes that were issued in
May of 2001 were outstanding and accruing interest for an additional five months
during 2002. The costs of the bond issue were also subject to amortization for
the entire year. The change in the fair value of our interest rate swap created
gains in both years, but the gain was larger in 2002 because interest rates were
decreasing during the year.

General and Administrative Expenses -- General and administrative expenses
totaled $12.7 million in the year ended December 31, 2002 as compared to $15.2
million in the year ended December 31, 2001, representing a decrease of 16.4%.
Salaries and benefits were $3.1 million lower in 2002 than in 2001, because of
early 2002 staff reductions. In addition, the termination of outsourcing
contracts reduced management fees by $1.6 million in 2002. However, these
decreases were partially offset by severance costs of $3.7 million in 2002
compared with $2.5 million of severance and outsourcing contract termination
fees in 2001.

FINANCIAL CONDITION

CAPITAL STRUCTURE

We have a highly leveraged capital structure, limiting our financial
flexibility. In particular, we must pay approximately $22.0 million of interest
annually on our long-term debt, which limits the amount of cash that is
available for exploration and development of oil and gas properties. In 2002,
management began evaluating alternatives to improve Mission's financial
position. In 2003, the following steps were taken to enhance our financial
condition:

- The March 2003 repurchase and retirement of approximately $97.6 million
of our senior subordinated notes financed with a $80.0 million term loan
facility.

- The establishment of a new revolving credit facility in June 2003, making
$12.5 million available for short-term borrowings.

- The issuance of 4.5 million shares of common stock in exchange for $10
million of our senior subordinated notes in December 2003.

- The sale of high-cost oil properties, making available approximately $25
million for re-investment in gas properties.

We intend to take additional actions in 2004 to continue to improve our
financial condition. Among the alternatives that we may consider are

- a refinancing of the remaining notes;

- a new credit facility;

- a merger with or an acquisition by another company;

- the acquisition by Mission of another company or assets;

32

- other secured and unsecured debt financings; and

- the issuance of equity securities or other debt securities for cash or
properties or in exchange for the notes.

FINANCING

Our outstanding indebtedness totaled $198.5 million at December 31, 2003.
The nature of our indebtedness at of December 31, 2003 and 2002 is summarized on
the table below (amounts in millions).

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

(1) Amounts available for borrowing at December 31, 2003 and 2002 under the
revolving credit facilities were $12.5 million and $40.0 million,
respectively.

Senior Subordinated Notes

In April 1997, we issued $100.0 million of 10 7/8% senior subordinated
notes due 2007. On May 29, 2001, we issued an additional $125.0 million of
senior subordinated notes due 2007, with identical terms to the notes issued in
April 1997, at a premium of $1.9 million. We amortize the premium as a reduction
of interest expense over the life of the notes so that the effective interest
rate on the additional notes is 10.5%. Through December 31, 2003, we had
amortized approximately $740,000 of the premium. Interest on the notes is
payable semi-annually on April 1st and October 1st.

We may choose to redeem the notes, in whole or in part, at any time after
April 1, 2000 at 105.44% plus accrued and unpaid interest. The required
redemption price decreases annually to 100% on April 1, 2005. Should Mission
effect a change of control, as defined in the indenture, the noteholders could
require us to purchase all or part of the notes for 101% plus accrued and unpaid
interest. The notes contain covenants that

- limit indebtedness and liens;

- require compliance with covenants of existing debt, such as our credit
facility;

- limit dividend payments and repurchases of capital stock;

- restrict payments to subsidiaries defined by the indenture as restricted
subsidiaries;

- control issuance and sales of stock of restricted subsidiaries;

- restrict the disposition of proceeds from asset sales; and

- restrict mergers and consolidations or sales of assets.

On March 28, 2003, we acquired, in a private transaction with various funds
affiliated with Farallon Capital Management, LLC, pursuant to the terms of a
purchase and sale agreement, approximately $97.6 million in principal amount of
the notes for approximately $71.7 million, plus accrued interest. Immediately
after the consummation of the transaction, Mission had $127.4 million in
principal amount of notes outstanding. Including costs of the transaction and
the removal of $2.2 million of previously deferred financing costs related to
the acquired notes, we recognized a $22.4 million gain on the extinguishment of
the notes.

33

On December 17, 2003, in a private transaction with FTVIPT -- Franklin
Income Securities Fund and Franklin Custodian Funds -- Income Series, we
acquired $10.0 million in principal amount of the notes in exchange for 4.5
million shares of our common stock. The stock was valued at $1.94 per share, the
opening price for the transaction date. After netting out costs of the
transaction and the removal of previously deferred financing costs and premium
related to the acquired notes, we recognized a net gain of approximately $1.1
million on this extinguishment of the notes.

We were in compliance with the covenants of the notes at December 31, 2003.
The notes require us to comply with covenants of other existing debt if
borrowings under that debt exceed $10.0 million. As discussed below under
"Credit Facility", Mission was also in compliance with all covenants of its
credit facilities at December 31, 2003.

As of December 31, 2003, Moody's published Mission's subordinated note
rating as "Ca". In determining Mission's debt rating, Moody's considers a number
of items including, but not limited to, debt levels, planned asset sales,
near-term and long-term production growth opportunities, capital allocation
challenges and commodity price levels. A decline in our ratings would not create
a default under our current credit facility or other unfavorable change.

Credit Facility

In 2002, Mission was party to a $150.0 million credit facility with a
syndicate of lenders. The credit facility was a revolving facility, expiring May
16, 2004, which allowed Mission to borrow, repay and re-borrow under the
facility from time to time. The total amount that might be borrowed under the
facility was limited by the borrowing base periodically set by the lenders based
on Mission's oil and gas reserves and other factors deemed relevant by the
lenders. The facility was repaid in full on March 28, 2003.

On March 28, 2003, simultaneously with the acquisition of the notes,
Mission amended and restated its credit facility with new lenders, led by
Farallon Energy Lending, LLC. Under the amended and restated secured credit
agreement (the "Facility"), Mission borrowed $80.0 million pursuant to term
loans (the "Term Loan Facility"), the proceeds of which were used to acquire
approximately $97.6 million face amount of notes, to pay accrued interest on the
notes purchased and to pay closing costs. On June 16, 2003, we amended the
Facility to add a revolving credit facility of up to $12.5 million (the
"Revolver Facility"), including a letter of credit sub-facility (the
"Sub-Facility") of up to $3.0 million. The Facility, which includes the Term
Loan Facility and the Revolver Facility, is secured by a lien on substantially
all of Mission's property and the property of all of our subsidiaries, including
a lien on at least 90% of our respective oil and gas properties and a pledge of
the capital stock of all the subsidiaries. The Term Loan Facility expires on
January 6, 2005, and the Revolver Facility expires on June 6, 2006.

The proceeds of the Revolver Facility are to be used to finance our ongoing
working capital and general corporate needs. As of December 31, 2003, we had no
amounts outstanding under the Revolver Facility, but had issued $100,000 of
letters of credit under the Sub-Facility. Subject to the terms and conditions of
the Revolver Facility, the lenders have agreed to make advances to Mission, from
time to time, prior to the expiration of the Revolver Facility, in an amount
equal to the least of the following (in whole multiples of $1,000,000):

(i) $12.5 million minus outstanding letters of credit,

(ii) the Borrowing Base (as defined below) minus outstanding letters
of credit, and

(iii) during a Cleanup Period (as defined below), $3.0 million minus
outstanding letters of credit in excess of $1.0 million.

"Borrowing Base" means an amount equal to 10% of the PV-10 Value (as
defined in the Facility) of the our proved developed producing reserves minus
certain other reserves required under the Facility. The

34

Borrowing Base was $13.2 million at December 31, 2003. A "Cleanup Period" is
either of the following periods if principal amounts under the Term Loan
Facility are outstanding:

(x) the 30-day period following any 90-day period in which the amount
outstanding under the Revolver Facility exceeds $3.0 million for each day,
or

(y) the one-day period immediately following any required payment on
any indebtedness subordinate to the Facility.

The interest rate under the Term Loan Facility is 12% until February 16,
2004, when it increases to 13% until the Maturity Date. The interest rate under
the Revolver Facility is equal to the prime rate plus 0.5% per annum, provided
that the minimum interest rate is 4.75% per annum. Outstanding letters of credit
are charged a letter of credit fee equal to 3.0% per annum.

The Facility contains covenants that limit our capital expenditures, except
for capital expenditures in the ordinary course of business that:

- do not exceed the amount approved by the majority lenders for fiscal year
2004; or

- are financed out of the net cash proceeds of issuances of capital stock
(effected during a 30 day period) in excess of $20.0 million or out of
the net cash proceeds of asset sales, with an aggregate limit of $50.0
million during the term of the loans outstanding under the Facility (the
"Loans"), (i) of up to $5.0 million during the term of the Loans, and
(ii) that are paid for the acquisition of replacement assets either 90
days before or 90 days after the asset sale or recovery event.

For fiscal years 2005 and thereafter, our capital expenditures cannot
exceed the amounts approved by the administrative agent and the majority
lenders.

In addition, there are certain other financial covenants in the Facility
that we consider important in operating our business:

- minimum consolidated EBITDA, as of the last day of any fiscal quarter,
for the period of two fiscal quarters that end on such day, of $17.5
million;

- maximum Leverage Ratio (as defined below) as at the last day of any
fiscal quarter of 2.75 to 1; and

- minimum Consolidated Fixed Charge Coverage Ratio (as defined below), must
be 1.00 to 1.00 at each fiscal quarter's end on a cumulative basis for
the first eight fiscal quarters. Thereafter the ratio must be 1.25 to
1.00 at quarter's end for the total of the four preceding fiscal
quarters.

"Leverage Ratio" is the ratio of (a) the principal amount of the Loans plus
the principal amount of all indebtedness that is equal to or senior in right of
payment to the Loans to (b) consolidated EBITDA for the period of four quarters
ending on such day. "Consolidated Fixed Charge Coverage Ratio" for any period,
is the ratio of: (a) the consolidated EBITDA during such period plus, for each
applicable test period ended on March 31, June 30, September 30, and December
31, of calendar years 2003 and 2004, plus $12,000,000 to (b) the sum of (i) our
capital expenditures during such period plus (ii) the cash income tax expense
for such period plus (iii) our cash consolidated interest expense for such
period to the extent paid or required to be paid during such period.

The Facility contains additional covenants that limit our ability, among
other things, to incur additional indebtedness or to create or incur liens; to
merge, consolidate, liquidate, wind-up or dissolve; to dispose of property; and
to pay dividends on or redeem stock. As of December 31, 2003, we were in
compliance with the covenants in the Facility.

At current oil and gas price levels, we expect to be in compliance with all
of the credit facility covenants throughout 2004. Declining commodity prices or
rising expenses could prevent us from meeting the credit facility covenants. In
that event, we would attempt to negotiate an amendment or a waiver of the
covenants from our lenders. Should the lenders fail to approve our requests,
then we would attempt to

35

obtain the funds to repay the outstanding credit facility debt through property
sales or equity financing. We cannot assure you that we would be successful in
completing any of these possible actions.

LIQUIDITY AND CAPITAL RESOURCES

Mission's principal sources of capital for the last three years have been
cash flow from operations, debt sources such as the issuance of bonds or credit
facility borrowings, issuances of common stock, and the sale of oil and gas
properties. Our primary uses of capital have been the funding of the retirement
of senior subordinated notes, exploration and development projects and property
acquisitions.

At December 31, 2003, we had working capital of $13.2 million compared to
$0.9 million at December 31, 2002. Cash held for reinvestment in oil and gas
properties of approximately $24.9 million is included in the December 31, 2003
working capital amount. Approximately $24.9 million of the proceeds from 2003
property sales were held for reinvestment at December 31, 2003. On January 30,
2004, we acquired the Jalmat field for $26.6 million, using these proceeds plus
operating cash flow. When this cash held for reinvestment is excluded, our
working capital becomes negative. The addition of a current obligation for asset
retirement as a result of the implementation of SFAS No. 143 and the unfavorable
impact of increased commodity prices on our hedges' fair value contributed most
significantly to working capital reduction in 2003. The hedge liability
represents the extent to which actual commodity prices exceed the price caps set
by our hedges. Should commodity prices decrease, the liability will decline and
the premium over the hedge prices that we will realize on unhedged production
will also reduce. Since hedges are settled out of the receipts from the sale of
production, we anticipate having adequate cash inflows to settle any hedge
payments when they come due while maintaining revenue near the hedge price. We
believe that cash flows from operating activities combined with our ability to
control the timing of substantially all of our future exploration and
development requirements will provide us with the flexibility and liquidity to
meet our planned capital requirements for 2004. Our Revolver Facility is also
available for short-term borrowings.

Source of Capital: Operations

Cash flow provided by operating activities totaled $18.8 million, $7.2
million, and $40.4 million for the fiscal years 2003, 2002, and 2001,
respectively. Our operating cash flow is sensitive to many variables, with
prices of oil, natural gas and NGL being the most volatile. Prices are
determined primarily by prevailing market conditions. Regional and worldwide
economic growth, weather and other variable factors influence market conditions.
We are not able to control these factors and may not be able to accurately
predict prices.

To mitigate some of the risk inherent in oil and natural gas prices, we
hedge our oil and natural gas production by entering into commodity price swaps
or collars designed to set minimum prices and maximum prices, or both, on a
portion of our production. See "Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk" for a more detailed discussion of commodity price
risk and a listing of our current hedges.

Source of Capital: Debt

Our outstanding balance under the 10 7/8% senior subordinated notes was
$117.4 million at December 31, 2003 and was $225.0 million at December 31, 2002
and 2001. In 2003, we purchased and retired $107.6 million of notes in two
transactions for $71.7 million in cash, from a $80.0 million term loan facility
established in March 2003, and by exchanging 4.5 million shares of common stock.

Borrowings under our credit facilities were $80.0 million in term loans at
December 31, 2003 and $35.0 million at the end of 2001. There were no borrowings
outstanding under our credit facility at December 31, 2002. Additionally, we
have $12.5 million of credit available under the Revolver Facility as of
December 31, 2003. As previously discussed under "Financing Activities," both
our notes and our credit facility contain covenants limiting our activities or
requiring that we maintain specific financial ratios. As of December 31, 2003,
we were in compliance with all applicable covenants.

36

Declining commodity prices or rising expenses could prevent us from meeting
the credit facility covenants. In that event, we would attempt to negotiate an
amendment or a waiver of the covenants from our lenders. Should the lenders fail
to approve our requests, then we would attempt to obtain the funds to repay the
outstanding credit facility debt through property sales or equity financing. We
cannot assure you that we would be successful in completing any of these
possible actions.

Source of Capital: Issuance of Common Stock

We issued 4.5 million shares of common stock on December 17, 2003 to
FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income
Series in order to acquire $10.0 million principal amount value of the senior
subordinated notes. These shares of common stock are currently registered for
resale under an effective registration statement. In February 2004, we acquired
$15.0 million of our 10 7/8% senior subordinated notes due 2007 for 6.25 million
shares of common stock in a transaction with Stellar Funding, Ltd. In addition,
we have agreed to register the resale of these shares of common stock.

Source of Capital: Sale of Properties

We continue to evaluate and assess our property portfolio and capital
needs, and we may from time to time sell certain properties as appropriate. Net
proceeds from the sales of oil and gas properties were approximately $28.1
million in 2003, $60.4 million in 2002, and $15.9 million in 2001. Net proceeds
are gross proceeds adjusted for transaction costs and interim operations. We
also sold our Ecuadorian interests for approximately $4.8 million in June 2001
and our interests in the Snyder and Diamond M gas plants for $10.9 million in
late 2001.

Use of Capital: Exploration and Development

Mission's expenditures for exploration, including land and seismic costs,
and development of its domestic oil and gas properties totaled $33.4 million,
$20.6 million, and $44.6 million for the fiscal years 2003, 2002, and 2001,
respectively. We also spent $3.9 million in the year 2001 on the development of
fields in Ecuador.

Our capital budget for 2004 is $32.0 million to $34.0 million.
Approximately 60% of the total is planned for development projects, while 20% is
planned for exploration. The remaining 20% is planned for seismic data, land and
land-related assets and corporate assets. Based upon the level of funding needed
for development, the level of exploratory spending could be modified to meet the
budget in total. This capital budget represents the largest planned use of our
available operating cash flow. We believe that cash flows from operating
activities combined with our ability to control the timing of substantially all
of our future exploration and development requirements will provide us with the
flexibility and liquidity to meet our planned capital requirements for 2004. Our
intent is to apply less than our discretionary cash flow to capital projects in
2004; therefore, the budget could be modified throughout the year to the extent
that we can control the timing of capital expenditures.

Use of Capital: Acquisitions and Other Corporate Assets

In 2003, spending for oil and gas property acquisitions was approximately
$1.6 million. The most significant individual acquisition was that of an
additional interest in High Island Block A-553 for approximately $621,000. We
did not make any significant oil and gas property acquisitions during 2002. The
merger with Bargo, valued at $280.9 million, was our most significant
acquisition of 2001. Other domestic property acquisitions totaled $23.4 million
in the year 2001.

We invested approximately $1.0 million in other corporate assets during
2003. These assets include a new computer system for land records and office
expansion to accommodate our growing workforce. Approximately $1.3 million will
be spent in 2004 for corporate assets.

We continuously review acquisition opportunities and would first consider
utilizing operating cash flows to make a desired acquisition. For larger
acquisitions, our credit facility or the issuance of equity

37

securities could provide the necessary funds, however, we cannot assure you that
either of these sources would be able to provide funds adequate to complete
every desired acquisition.

Approximately $24.9 million of the proceeds from 2003 property sales was
held for reinvestment at December 31, 2003. The proceeds were used to fund the
$26.6 million acquisition of the Jalmat field in the Permian Basin.

Use of Capital: Contractual Obligations and Commercial Commitments

Mission is required to make future payments under contractual obligations.
The following table details those future payments (amounts in thousands):

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

* Includes bond principal of $117.4 million scheduled for repayment in 2007 and
bond interest accrued monthly and payable April 1st and October 1st of each
year.

Mission has also made various commitments in the future should certain
events occur or conditions exist. The estimated payments related to those
commitments are scheduled on the table below (amounts in thousands):

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

* Includes delay rentals required to hold undeveloped acres for future drilling.

CRITICAL ACCOUNTING POLICIES

In response to SEC Release No. 33-8040, "Cautionary Advice Regarding
Disclosure About Critical Accounting Policies," we identified those policies of
particular importance to the portrayal of our financial position and results of
operations and those policies that require our management to apply significant
judgment. We believe these critical accounting policies affect the more
significant judgments and estimates used in the preparation of our consolidated
financial statements.

FULL COST METHOD OF ACCOUNTING FOR OIL AND GAS ASSETS

We use the full cost method of accounting for investments in oil and gas
properties. Under the full cost method of accounting, all costs of acquisition,
exploration and development of oil and gas reserves are capitalized as incurred
into a "full cost pool". Under the full cost method, a portion of
employee-related costs may be capitalized in the full cost pool if they are
directly identified with acquisition, exploration and development activities.
Generally, salaries and benefits are allocated based upon time spent on
projects. Amounts capitalized can be significant when exploration and major
development activities increase.

We deplete the capitalized costs in the full cost pool, plus estimated
future expenditures to develop reserves, on a prospective basis using the units
of production method based upon the ratio of current production to total proved
reserves. Depreciation, depletion and amortization is a significant component of
our net income. Proportionally, it represented 38% of our total oil and gas
revenues in the years ended December 31, 2003 and 2002. Any reduction in proved
reserves without a corresponding reduction in capitalized costs will increase
the depletion rate. If during 2004, our reserves increase by 10%, our depletion
per MCFE would decrease approximately $0.18, or 9%; however, a 10% decrease in
reserves will have a 11% impact, increasing depletion per MCFE by approximately
$0.21.

38

Both the volume of proved reserves and the estimated future expenditures
used for the depletion calculation are obtained from the reserve estimates
prepared by independent reserve engineers. These reserve estimates rely upon
both the engineers' quantitative and subjective analysis of various data, such
as engineering data, production trends and forecasts, estimated future spending
and the timing of spending. Finally, estimated production costs and commodity
prices are added to the assessment in order to determine whether the estimated
reserves have any value. Reserves that cannot be produced and sold at a profit
are not included in the estimated total proved reserves; therefore the quantity
of reserves can increase or decrease as oil and gas prices change. See "Risk
Factors: Risks Related to Our Business, Industry and Strategy" for general
cautions concerning the reliability of reserve and future net revenue estimates
by reserve engineers.

The full cost method requires a quarterly calculation of a limitation on
capitalized costs, often referred to as a full cost ceiling calculation. The
ceiling is the discounted present value of our estimated total proved reserves
adjusted for taxes, using a 10% discount rate. To the extent that our
capitalized costs (net of depreciation, depletion, amortization, and deferred
taxes) exceed the ceiling, the excess must be written off to expense. Once
incurred, this impairment of oil and gas properties is not reversible at a later
date even if oil and gas prices increase. No such impairment was required in the
years ended December 31, 2003 and 2002.

While the difficulty in estimating proved reserves could cause the
likelihood of a ceiling impairment to be difficult to predict, the impact of
changes in oil and gas prices is most significant. In general, the ceiling is
lower when prices are lower. Oil and gas prices at the end of the period are
applied to the estimated reserves, then costs are deducted to arrive at future
net revenues, which are then discounted at 10% to arrive at the discounted
present value of proved reserves. Additionally, we adjust the estimated future
revenues for the impact of our existing cash flow commodity hedges. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are generally held constant indefinitely. Therefore, the future net
revenues associated with the estimated proved reserves are not based on
Mission's assessment of future prices or costs, but rather are based on prices
and costs in effect as of the end the period.

Because the ceiling calculation dictates that prices in effect as of the
last day of the period be held constant, the resulting value is rarely
indicative of the true fair value of our reserves. Oil and natural gas prices
have historically been variable and, on any particular day at the end of a
period, can be either substantially higher or lower than our long-term price
forecast, which we feel is more indicative of our reserve value. You should not
view full cost ceiling impairments caused by fluctuating prices, as opposed to
reductions in reserve volumes, as an absolute indicator of a reduction in the
ultimate value of our reserves.

Oil and gas prices used in the ceiling calculation at December 31, 2003
were $32.47 per barrel and $5.97 per MMBTU. A significant reduction in these
prices at a future measurement date could trigger a full cost ceiling
impairment. As an illustration, had oil and gas prices at December 31, 2003 been
10% lower, we would have been 69% closer to a ceiling impairment. Our hedging
program would serve to mitigate some of the impact of any price decline. If our
hedges were excluded from the ceiling calculation, we would have been 62% closer
to a ceiling impairment.

DERIVATIVE INSTRUMENTS ACCOUNTING

All of our commodity derivative instruments represent hedges of the price
of future oil and natural gas production. We estimate the fair values of our
hedges at the end of each reporting period. The estimated fair values of our
commodity derivative instruments are recorded in the consolidated Balance Sheet
as assets or liabilities as appropriate.

For effective hedges, we record the change in the fair value of the hedge
instruments to other comprehensive income, a component of stockholders' equity,
until the hedged oil or natural gas quantities are produced. Any ineffectiveness
in our hedges, which could represent either gains or losses, is reported when
calculated as part of the interest and other income line of the Statement of
Operations

39

Estimating the fair values of commodity hedge derivatives requires complex
calculations, including the use of a discounted cash flow technique and our
subjective judgment in selecting an appropriate discount rate. In addition, the
calculation uses future NYMEX prices, which although posted for trading
purposes, are merely the market consensus of forecast price trends. The results
of our fair value calculation cannot be expected to represent exactly the fair
value of our commodity hedges. We currently use a software product from an
outside vendor to calculate the fair value of our hedges. This vendor provides
the necessary NYMEX futures prices and the calculated volatility in those prices
to us daily. The software is programmed to apply a consistent discounted cash
flow technique, using these variables and a discount rate derived from
prevailing interest rates. This software is successfully used by several of our
peers. Its methods are in compliance with the requirements of SFAS No. 133 and
have been reviewed by a national accounting firm.

REVENUE RECOGNITION

Mission records revenues from sales of crude oil and natural gas when
delivery to the customer has occurred and title has transferred. This occurs
when production has been delivered to a pipeline or a tanker lifting has
occurred. We may share ownership with other producers in certain properties. In
this case, we use the sales method to account for sales of production. It is
customary in the industry for various working interest partners to sell more or
less than their entitled share of natural gas production, creating gas
imbalances. Under the sales method, gas sales are recorded when revenue checks
are received or are receivable on the accrual basis. Typically no provision is
made on the Balance Sheet to account for potential amounts due to or from
Mission related to gas imbalances. If the gas reserves attributable to a
property have depleted to the point that there are insufficient reserves to
satisfy existing imbalance positions, a liability or a receivable, as
appropriate, should be recorded equal to the net value of the imbalance. As of
December 31, 2003, the Company had recorded a net liability of approximately
$1.1 million, representing approximately 379,000 MCF at an average price of
$2.95 per MCF, related to imbalances on properties at or nearing depletion. The
net liability accrued as of December 31, 2002, was $454,000 for approximately
266,000 MCF at an average price of $1.71 per MCF. We value gas imbalances using
the price at which the imbalance originated, if required by the gas balancing
agreement, or we use the current price where there is no gas balancing agreement
available. Reserve changes on any fields that have imbalances could change this
liability. We do not anticipate the settlement of gas imbalances to adversely
impact our financial condition in the future. Settlements are typically
negotiated, so the per Mcf price for which imbalances are settled could differ
among wells and even among owners in one well. Exclusive of the liability
recorded for properties at or nearing depletion (see discussion above), the
Company's unrecorded imbalance, valued at current prices would be a $1.7 million
liability.

ASSET RETIREMENT, IMPAIRMENT OR DISPOSAL

We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations"
effective January 1, 2003. Previously our estimate of future plugging and
abandonment and dismantlement costs was charged to income by being included in
the capitalized costs that we depleted using the unit of production method. SFAS
No. 143 requires us to record a liability for the fair value of our estimated
asset retirement obligation, primarily comprised of our plugging and abandonment
liabilities, in the period in which it is incurred. Upon initial implementation,
we estimate asset retirement costs for all of our assets as of such date,
inflation adjust those costs to the forecast abandonment date, discount that
amount back to the date we acquired the asset and record an asset retirement
liability in that amount with a corresponding addition to our asset value. Then
we must compute all depletion previously taken on future plugging and
abandonment costs, and reverse that depletion. Finally, we must accrete the
liability to present day. Any income effect of this initial implementation is
reflected as a change in accounting method on our Statement of Operations.

After initial implementation, we will reduce the liability as abandonment
costs are incurred. Should actual costs incurred to abandon a field differ from
the estimate, the difference will be reflected as an abandonment gain or loss in
the Statement of Operations when the field is abandoned. We will accrete the

40

liability quarterly using the period and effective interest rates determined at
implementation. As new wells are drilled or purchased their initial asset
retirement cost and liability will be calculated and recorded. We have developed
a process through which to track and monitor the obligations for each asset
following implementation of SFAS No. 143.

When wells are sold the related liability and asset cost are removed from
the Balance Sheet. Any difference between the two remains in the full cost pool.
SFAS No. 143 does not specifically address the proper accounting to be applied
by a full cost method company when properties are sold. A May 23, 2003 letter to
the FASB and the SEC from a group of concerned companies makes inquiries and
outlines possible alternatives, including our current treatment. Should a
clarification be issued, there is a chance that Mission's treatment will be
required to change and the entire $2.2 million credit that is in our full cost
pool for 2003 would have to be included in income.

As with previously discussed estimates, the estimation of our initial
liability and its subsequent remeasurements is dependent upon many variables. We
attempt to limit the impact of management's judgment on these variables by using
the input of qualified third parties when possible. We engaged an independent
engineering firm to evaluate our properties annually and to provide us with
estimates of abandonment costs. We used the remaining estimated useful life from
the yearend Netherland, Sewell & Associates, Inc. reserve report in estimating
when abandonment could be expected for each property. The resulting estimate,
after application of a discount factor and some significant calculations, could
differ from actual results, despite all our efforts to make the most accurate
estimation possible.

Should either the estimated life or the estimated abandonment costs of a
property change upon subsequent review, a new calculation is performed using the
same methodology of taking the abandonment cost and inflating it forward to its
abandonment date and then discounting it back to the present using our risked
rate. The carrying value of the asset retirement obligation is adjusted to the
newly calculated value, with a corresponding offsetting adjustment to the asset
retirement cost.

INCOME TAXES

Mission has accumulated substantial income tax deductions that have not yet
been used to reduce cash income taxes actually paid with the filing of our
income tax returns. These accumulated deductions are commonly referred to as
"net operating loss carryforwards" or "NOLs".

Our NOLs are, subject to a number of restrictions, available to reduce cash
taxes that may become owed in future years. In accordance with the accounting
for income taxes under SFAS No. 109, we record a deferred tax asset and a
reduction of our tax expense for our NOLs. If we estimate that some or all of
our NOL's are more likely than not going to expire or otherwise not be utilized
to reduce future tax, we record a valuation allowance to remove the benefit of
those NOL's from our financial statements

One of the restrictions on the future use of NOLs is contained in Section
382 of the Internal Revenue Code. In general, Section 382 provides that the
amount of existing NOLs that may be used to offset future taxable income after
the occurrence of an "ownership change" (as defined solely for Section 382
purposes) is limited to an amount that is determined, in part, by the fair
market value of the enterprise at the time the ownership change occurred. The
fair market value of the enterprise's individual assets and the timing in which
the value of those assets are realized are also factors that impact the amount
of NOLs available under Section 382 ("382 Limitation").

As a result of our issuance of common stock in exchange for the retirement
of a portion of our 10 7/8% senior subordinated notes in December 2003, we
experienced an "ownership change" as defined under Section 382. Consequently, we
have included the estimated impact that a 382 Limitation may have upon the
future availability of our NOLs as part of our evaluation under SFAS 109.

Consistent with previously described estimates, the initial estimation of
the future benefit of our NOLs is dependent upon many variables and is subject
to change. Management's judgment on these variables is based upon the input of
qualified third parties when possible. We have used information derived from the
public equity markets as well as data provided by an independent engineering
firm to

41

assist us with determining fair market values. We have engaged an international
independent public accounting firm to assist us in applying the numerous and
complicated tax law requirements. However, despite our attempt to make the most
accurate estimates possible, the ultimate utilization of our NOLs is highly
dependent upon our actual production and the realization of taxable income in
future periods.

OTHER MATTERS

DIVIDENDS

At present, there is no plan to pay dividends on our common stock. Certain
restrictions contained in Mission's outstanding notes and credit facility limit
the amount of dividends that may be declared.

NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statements No. 13 and Technical Corrections, was issued in April 2002. SFAS
No. 145 amends existing guidance on reporting gains and losses on the
extinguishments of debt to prohibit the classification of the gain or loss as
extraordinary, as the use of such extinguishments have become part of the risk
management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to
require sale-leaseback accounting for certain lease modifications that have
economic effects similar to sale-leaseback transactions. The provision of the
Statement related to the rescission of Statement No. 4 is applied in fiscal
years beginning after May 15, 2002. Earlier application of these provisions is
encouraged. The provisions of the Statement related to Statement No. 13 were
effective for transactions occurring after May 15, 2002, with early application
encouraged. Mission applied the provisions of SFAS No. 145 as they relate to the
extinguishment of debt in accounting for the March 28, 2003 senior subordinated
note repurchase and the December 17, 2003 debt for equity swap which are further
discussed in the notes to consolidated financial statements at footnote 8.

SFAS No. 146, Accounting for Exit or Disposal Activities, was issued in
June 2002. SFAS No. 146 addresses significant issues regarding the recognition,
measurement, and reporting of costs that are associated with exit and disposal
activities, including restructuring activities that are currently accounted for
pursuant to the guidance set forth in EITF Issue No. 94-3, Liability Recognition
of Certain Employee Termination Benefits and Other Costs to Exit an Activity.
SFAS No. 146 is effective for the exit and disposal activities initiated after
December 31, 2002. We applied SFAS No. 146 to the closings of our offices
located in Longview, Texas and Belleville, Texas. The fields served by these
offices were sold during the fourth quarter of 2003. All activities required to
close the offices and to establish one replacement office nearer to the
Company's remaining operated properties were concluded during 2003. An aggregate
loss of approximately $136,000 was recognized in connection with these office
closings, with almost $122,000 of the total related to severance payments made
in accordance with Mission's existing severance plan. This loss is included in
the interest and other income line of the Statement of Operations.

In November 2002, FASB issued Interpretation No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107
and a rescission of FASB Interpretation No. 34. This interpretation elaborates
on the disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under guarantees issued. The interpretation
also clarifies that a guarantor is required to recognize, at inception of a
guarantee, a liability for the fair value of the obligation undertaken. The
initial recognition and measurement provisions of the interpretation are
applicable to guarantees issued or modified after December 31, 2002 and were not
expected to materially effect our financial statements. The disclosure
requirements are effective for financial statements of interim and annual
periods ending after December 15, 2002 and can be found in the notes to
consolidated financial statements at footnote 12.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment of SFAS No. 123, that
provides alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent

42

disclosures in both annual and interim financial statements. Some of the
disclosure modifications are required for fiscal years ending after December 15,
2002 and are included in the notes to consolidated financial statements at
footnotes 2 and 5.

FASB issued Interpretation No. 46, Consolidation of Variable Interest
Entities, an interpretation of APB No. 51, in January 2003. This interpretation
addresses the consolidation by business enterprises of variable interest
entities as defined in the interpretation. The interpretation applied
immediately to variable interest entities created after January 31, 2003, and to
variable interests in variable interest entities obtained after January 31,
2003. Significant changes to this interpretation were proposed by FASB in
October 2003, including delaying the effective date to the beginning of the
first reporting period ending after December 15, 2003. Mission does not
currently own an interest in any variable interest entities; therefore, this
interpretation does not have a material effect on its financial statements. We
will apply the provisions of this interpretation in the future should we acquire
or establish a variable interest entity.

SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities Summary was issued in April 2003. This statement amends and
clarifies the accounting and reporting for derivative instruments, including
embedded derivatives, and for hedging activities under SFAS No. 133. Statement
149 amends Statement 133 to reflect the decisions made as part of the
Derivatives Implementation Group (DIG) and in other FASB projects or
deliberations. Statement 149 is effective for contracts entered into or modified
after June 30, 2003, and for hedging relationships designated after June 30,
2003. Mission has applied the pertinent DIG interpretations as they were issued
and does not expect SFAS No. 149 will have a material impact on our financial
statements.

SFAS No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity was issued in May 2003. SFAS No.
150 provides guidance on how to classify and measure certain financial
instruments with characteristics of both liabilities and equity. Many of these
instruments were previously classified as equity. This statement is effective
for financial instruments entered into or modified after May 31, 2003, and
otherwise is effective at the beginning of the first interim period beginning
after June 15, 2003. The statement requires cumulative effect transition for
financial instruments existing at adoption date. None of our financial
instruments were impacted by this statement.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Mission is exposed to market risk, including adverse changes in commodity
prices and interest rates. To the extent that we use derivative instruments to
mitigate these risks, we are also exposed to credit risk.

COMMODITY PRICE RISK

Mission produces and sells crude oil, natural gas and natural gas liquids.
As a result, our operating results can be significantly affected by fluctuations
in commodity prices caused by changing market forces. We periodically seek to
reduce our exposure to price volatility by hedging a portion of production
through swaps, options and other commodity derivative instruments. A combination
of options, structured as a collar, is our preferred hedge instrument because
there are no up-front costs and protection is given against low prices. These
collars assure that the NYMEX prices we receive on the hedged production will be
no lower than the price floor and no higher than the price ceiling. The oil
hedges that are swaps fix the price to be received.

Our realized price, excluding hedges, for natural gas per MCF is generally
$0.19 less than the NYMEX MMBTU price. Our realized price, excluding hedges, for
oil is generally $0.81 per BBL less than NYMEX. Realized prices differ from
NYMEX due to factors such as the location of the property, the heating content
of natural gas and the quality of oil. The oil differential excludes the impact
of Point Pedernales field production for which our selling price is capped at
$9.00 per BBL. The Point Pedernales field was sold in March 2003 to the
operator. The gas differential stated above excludes the impact of the Mist
field gas production, which is sold at an annually fixed price.

43

In May 2002 several existing oil collars were cancelled. New swaps and
collars hedging forecast oil production were acquired. We paid approximately
$3.3 million, the fair value of the previous oil price collars at that time, to
counter parties in order to cancel the transactions.

By removing the price volatility from hedged volumes of oil and natural gas
production, we have mitigated, but not eliminated, the potential negative effect
of declining prices on our operating cash flow. The potential for increased
operating cash flow due to increasing prices has also been reduced. If all our
commodity hedges were to settle at December 31, 2003 prices, our cash flows
would decrease by $10.5 million; however the actual settlement of our hedges
will increase or decrease cash flows over the period of the hedges at varying
prices.

The following tables detail our commodity hedges as of March 8, 2004.

OIL HEDGES

GAS HEDGES

CREDIT RISK

These commodity hedges expose Mission to counter party credit risk to the
extent the counter party is unable to meet its monthly settlement commitment to
us. We believe that we select creditworthy counter parties to our hedge
transactions. Each of our counter parties have long-term senior unsecured debt
ratings of at least A/A2 by Standard & Poor's or Moody's.

INTEREST RATE RISK

Effective September 22, 1998, Mission entered into an eight and one-half
year interest rate swap agreement with a notional value of $80.0 million. Under
the agreement, Mission received a fixed interest rate and paid a floating
interest rate, subject to a cap, based on the simple average of three foreign
LIBOR rates. Mission paid $1.3 million to the counter party in February 2003 to
cancel the swap. A $520,000 gain related to the change in the fair market value
of the swap from January 1, 2003 to the date of cancellation was recognized as a
reduction in interest expense.

44

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

45

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Mission Resources Corporation and Subsidiaries:

We have audited the accompanying consolidated balance sheets of Mission
Resources Corporation (formerly Bellwether Exploration Company) and subsidiaries
as of December 31, 2003 and 2002 and the related consolidated statements of
operations, changes in stockholders' equity and comprehensive loss, and cash
flows for each of the years in the three-year period ended December 31, 2003.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mission
Resources Corporation and subsidiaries as of December 31, 2003 and 2002 and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statements, effective
January 1, 2003, the Company adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations." As discussed in note 2 to the consolidated financial statements,
effective January 1, 2002, the Company adopted the provisions of SFAS No. 142,
"Goodwill and Other Intangible Assets." As discussed in note 2 to the
consolidated financial statements, effective January 1, 2001, the Company
adopted the provisions of SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities."

KPMG LLP
Houston, Texas
February 27, 2004

46

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to Consolidated Financial Statements.
47

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS -- (CONTINUED)

See Notes to Consolidated Financial Statements.
48

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See Notes to Consolidated Financial Statements.
49

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES
IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME OR LOSS

See Notes to Consolidated Financial Statements.
50

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Notes to Consolidated Financial Statements.
51

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)

See Notes to Consolidated Financial Statements.
52

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

Mission Resources Corporation (the "Company" or "Mission") is an
independent oil and gas exploration and production company. We develop and
produce crude oil and natural gas. Mission's balanced portfolio comprises assets
located in the Permian Basin (West Texas and Southeast New Mexico), along the
Texas and Louisiana Gulf Coast and in the Gulf of Mexico. Our operational focus
is on property enhancement through development drilling, operating cost
reduction, low to moderate risk exploration, asset redeployment and acquisitions
of properties in the right circumstances.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Mission
Resources Corporation and its wholly owned subsidiaries. Mission owns a 26.6%
interest in the White Shoal Pipeline Corporation that is accounted for using the
equity method. Mission's investment of approximately $362,000 at December 31,
2003 is included in the other assets line of the Consolidated Balance Sheet.
Mission has not received any distributions from White Shoal Pipeline
Corporation. Mission had a 10.1% ownership in the East Texas Salt Water Disposal
Company that was accounted for using the cost method. It was reported at
$861,000 in the other assets line of the Consolidated Balance Sheet at December
31, 2002. This interest was sold in December 2003 in connection with the sale of
several oil and gas properties in the East Texas area.

In 1999, the Company invested in a Canadian company ("Carpatsky") that had
the right to produce and sell oil and gas from two fields in the Ukraine. Due to
different business and cultural approaches, foreign regulations and financial
limitations, the Company did not have significant influence over Carpatsky;
therefore the investment in Carpatsky was reflected using the cost method. In
June 2001, the Company exchanged its interests in Carpatsky for a production
payment on Carpatsky's producing properties, reporting $6.2 million as a
long-term receivable. In the fourth quarter of 2001, due to increased
uncertainties in world markets and declining commodity prices and uncertainties
related to the collectibility of the receivable, it was charged to expense as
part of the impairments line on the Consolidated Statement of Operations.

OIL AND GAS PROPERTIES

Full Cost Pool -- The Company utilizes the full cost method to account for
its investment in oil and gas properties. Under this method, all costs of
acquisition, exploration and development of oil and gas reserves (including such
costs as leasehold acquisition costs, geological expenditures, dry hole costs
and tangible and intangible development costs and direct internal costs) are
capitalized as the cost of oil and gas properties when incurred. Direct internal
costs that are capitalized are primarily the salary and benefits of geologists
and engineers directly involved in acquisition, exploration and development
activities, and amounted to $1.8 million, $1.3 million, and $3.2 million in the
years ended December 31, 2003, 2002 and 2001, respectively. Until June 2001, the
Company had two full cost pools: United States and Ecuador. The Company's
interests in Ecuador were sold in June 2001 for gross proceeds of $8.5 million.
Because the Ecuador sale involved the entire full cost pool, the book value of
the pool was removed from the Consolidated Balance Sheet and the resulting $12.7
million excess of book value over proceeds was reported as part of the loss on
sale of assets line of the Consolidated Statement of Operations for the year
ended December 31, 2001.

Over the past several months, a reporting issue has arisen regarding the
application of certain provisions of Statement of Financial Accounting Standards
("SFAS") SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. This matter has recently been taken up by the
Emerging Issues Task Force. The issue is whether SFAS No. 141 requires
registrants to

53

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

classify the costs of mineral rights associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide additional specific footnote disclosures.
Historically, the Company has included the costs of mineral rights associated
with extracting oil and gas as a component of oil and gas properties. If it is
ultimately determined that SFAS No. 141 requires oil and gas companies to
classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, the Company believes
it would be required to reclassify less than $1.0 million out of oil and gas
properties and into a separate intangible assets line item. These costs include
those to acquire contract based drilling and mineral use rights such as delay
rentals, lease bonuses, commissions and brokerage fees, and other leasehold
costs. The Company's cash flows and results of operations would not be affected
since such intangible assets would continue to be depleted and assessed for
impairment in accordance with full cost accounting rules, as allowed by SFAS No.
142. Further, the Company does not believe the classification of the costs of
mineral rights associated with extracting oil and gas as intangible assets would
have any impact on the Company's compliance with covenants under its debt
agreements. The Company will continue to classify its oil and gas leasehold
costs as tangible oil and gas properties until further guidance is provided.

Depletion -- The cost of oil and gas properties, the estimated future
expenditures to develop proved reserves, and estimated future abandonment, site
remediation and dismantlement costs are depleted and charged to operations using
the unit-of-production method based on the ratio of current production to proved
oil and gas reserves as estimated by independent engineering consultants as of
the beginning of the reporting period. Costs directly associated with the
acquisition and evaluation of unproved properties are excluded from the
amortization computation until it is determined whether or not proved reserves
can be assigned to the properties or whether impairment has occurred. Depletion
expense per thousand cubic feet of gas equivalent ("MCFE") was approximately
$1.65 in 2003, $1.29 in 2002, and $1.12 in 2001.

Unproved Property Costs -- The following table shows, by category of cost
and date incurred, the domestic unproved property costs excluded from
amortization (amounts in thousands):

Such unproved property costs fall into four broad categories:

- Material projects which are in the last one to two years of seismic
evaluation;

- Material projects currently being marketed to third parties;

- Leasehold and seismic costs for projects not yet evaluated; and

- Drilling and completion costs for projects in progress at year-end that
have not resulted in the recognition of reserves at December 31, 2003.
This category of costs will transfer into the full cost pool in 2004.

54

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Approximately $2.8 million, $2.2 million, and $1.8 million were evaluated and
moved to the full cost pool in 2003, 2002 and 2001, respectively.

Sales of Properties -- Dispositions of oil and gas properties held in the
full cost pool are recorded as adjustments to net capitalized costs, with no
gain or loss recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas. Net
proceeds from property sales of $28.1 million, $60.4 million, and $15.9 million
were recorded in such manner during the years 2003, 2002, and 2001,
respectively.

Impairment -- To the extent that capitalized costs of oil and gas
properties, net of accumulated depreciation, depletion and amortization, exceed
the discounted future net revenues of proved oil and gas reserves net of
deferred taxes, such excess capitalized costs would be charged to operations as
an impairment. Oil and gas prices as of December 31, 2003 were $32.47 per barrel
of oil (NYMEX WTI Cushing) and $5.97 per MMBTU of gas (NYMEX Henry Hub). Such
closing prices, adjusted to the wellhead to reflect adjustments for marketing,
quality and heating content, were used to determine discounted future net
revenues for the Company. In addition, the Company adjusted discounted future
net revenues to reflect the potential impact of its commodity hedges that
qualify for hedge accounting under SFAS No. 133. This adjustment was calculated
by taking the difference between the closing NYMEX spot prices and the price
ceiling on the Company's hedges multiplied by the hedged volumes that were
included in proved reserves. This calculation resulted in a decrease in
discounted future net revenues of $10.5 million because prices prevailing at
December 31, 2003 were higher than most of the Company's price ceilings.

The Company's capitalized costs were not in excess of these adjusted
discounted future net revenues as of December 31, 2003 and 2002; therefore no
impairment was required. The Company, however, recorded an oil and gas property
impairment of $20.8 million in 2001 because capitalized costs exceeded adjusted
discounted future net revenues. The impairment was shown on the impairment
expense line of the Consolidated Statement of Operations.

Any reference to oil and gas reserve information in the Notes to
Consolidated Financial Statements is unaudited.

GAS PLANTS

On October 1, 2001, the Company sold its interest in the Snyder gas plant
and Diamond M gas plant for gross proceeds of $11.5 million and recorded a gain
of $1.1 million. The gain nets against a loss realized on the sale of the
Company's Ecuadorian oil and gas assets on the loss on sale of assets line of
the Consolidated Statement of Operations for the year ended December 31, 2001.

REVENUE RECOGNITION AND GAS IMBALANCES

Revenues are recognized and accrued as production occurs. In 2001, the only
customer accounting for greater than 10% of oil and gas revenues was an
affiliate of Torch Energy Advisors ("Torch"). Sales to Torch were $43.3 million
and were part of domestic revenues. In 2002, no one customer accounted for
greater than 10% of oil and gas revenues. In 2003, sales to Shell Trading (US)
Company totaled approximately $19.7 million and accounted for 21.5% of the
Company's oil and gas revenues exclusive of the impact of hedges.

The Company uses the sales method of accounting for revenue. Under this
method, oil and gas revenues are recorded for the amount of oil and natural gas
production sold to purchasers. Gas imbalances are created, but not recorded,
when the sales amount is not equal to the Company's entitled share of
production. The Company's entitled share is calculated as the total or gross
production of the property multiplied by the Company's decimal interest in the
property. No provision is made unless the gas reserves
55

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

attributable to a property have depleted to the point that there are
insufficient reserves to satisfy existing imbalance positions. Then a liability
or a receivable, as appropriate, is recorded equal to the net value of the
imbalance. As of December 31, 2003, the Company had recorded a net liability of
approximately $1.1 million, representing approximately 379,000 MCF at an average
price of $2.95 per MCF, related to imbalances on properties at or nearing
depletion. The net liability accrued as of December 31, 2002, was $454,000 for
approximately 266,000 MCF at an average price of $1.71 per MCF. The gas
imbalances were valued using the price at which the imbalance originated if
there is a gas balancing agreement or the current price where there is no gas
balancing agreement. Reserve reductions on any fields that have imbalances could
cause this liability to increase. Settlements are typically negotiated, so the
per MCF price for which imbalances are settled could differ among wells and even
among owners in one well. Exclusive of the liability recorded for properties at
or nearing depletion (see discussion above), the Company's remaining unrecorded
imbalance, valued at current prices, would be a $1.7 million liability.

RECEIVABLES

The Company records receivables at their net realizable value using the
specific write off method of accounting for receivables. Joint interest billing
receivables represent those amounts due to the Company as operator of an oil and
gas property by the other working interest partners. Since these partners could
also be the operator of other properties in which the Company is a working
interest partner, the interdependency of the partners tends to assure timely
payment. Past due balances over 90 days and over $30,000 are reviewed for
collectibility monthly, and charged against earnings when the potential for
collection is determined to be remote. The Company has recognized bad debt
expense, included in interest and other income on the Consolidated Statement of
Operations, of $185,000, and $430,000 related to such receivables for the years
ended December 31, 2002 and 2001, respectively. In 2003, the Company made full
or partial collection of several previously written off balances for a net gain
of approximately $109,000. At December 31, 2003, one partner's outstanding
balance accounts for approximately 22% of the total receivable and approximately
88% of that outstanding balance is less than 45 days old. No other customers
account for more than 15% of the Company's outstanding receivables. The Company
does not have any off-balance sheet credit exposure related to its customers.

From time to time, certain other receivables are created and may be
significant. At December 31, 2003, the Company has recorded a receivable of
approximately $2.4 million from its insurance carrier, representing repair costs
incurred as a direct result of hurricane Lili in 2002

A portion of the Company's November 2001 gas production was sold under
contract to a subsidiary of Enron Corporation ("Enron"). Payment for that
production totaling $2.2 million was due in December 2001 and was not received.
Due to Enron's bankruptcy filing and continued legal difficulties, the Company
chose to write off the entire amount due from Enron. A separate line for
uncollectible gas revenues was added to the Consolidated Statement of Operations
in order to clearly segregate the $2.2 million charge to income recognized in
2001 due to Enron's failure to make payment.

CASH HELD FOR REINVESTMENT

The approximately $24.9 million shown on the Consolidated Balance Sheet as
cash held for reinvestment represents the net proceeds of the oil and gas
property sales that were closed during the fourth quarter of 2003. The Company's
credit facility requires that sale proceeds in excess of $5.0 million be
reinvested in approved replacement oil and gas properties. If no adequate
replacement is found, then the sale proceeds are to be used to pay down the
outstanding long-term debt. The Company did reinvest the sale proceeds by
acquiring the Jalmat field in the Permian Basin on January 30, 2004.

56

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INCOME TAXES

Deferred taxes are accounted for under the asset and liability method of
accounting for income taxes. Under this method, deferred income taxes are
recognized for the tax consequences of "temporary differences" by applying
enacted statutory tax rates applicable to future years to differences between
the financial statement carrying amounts and the tax basis of existing assets
and liabilities. The ultimate realization of deferred tax assets is dependent
upon the recognition of future taxable income in periods when the temporary
differences are available. The effect on deferred taxes of a change in tax rates
is recognized in income in the period the change occurs.

STATEMENTS OF CASH FLOWS

For cash flow presentation purposes, the Company considers all highly
liquid instruments purchased with an original maturity of three months or less
to be cash equivalents. Interest paid in cash for the years ended December 31,
2003, 2002 and 2001, was $26.7 million, $26.4 million, and $19.0 million,
respectively. Income taxes paid in cash, net of cash refunds, for the year ended
December 31, 2001 were $2.5 million. Net cash refunds of approximately $0.5
million and $1.8 million were received in the years ended December 31, 2003 and
2002, respectively.

On December 17, 2003, the Company exchanged 4.5 million shares of its
common stock, valued at the market price of $1.94 per share for purposes of
recording the exchange, for $10 million aggregate principal amount of its
10 7/8% senior subordinated notes due 2007. FTVIPT -- Franklin Income Securities
Fund and Franklin Custodian Funds -- Income Series were the recipients of the
shares in this non-cash transaction.

A significant portion of the funding of the 2001 Bargo merger was non-cash
as follows (amounts in thousands):

BENEFIT PLANS

During 1993, the Company adopted the Mission Resources Simplified Employee
Pension Plan (the "Savings Plan") whereby all employees of the Company are
eligible to participate. The Savings Plan is administered by a Plan
Administrator appointed by the Company. Eligible employees may contribute a
portion of their annual compensation up to the legal maximum established by the
Internal Revenue Service for each plan year. The Company matches contributions
up to a maximum of 6% each plan year. Employee contributions are immediately
vested and employer contributions have a four-year vesting period.

57

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Amounts contributed by the Company to the Savings Plan for the years ended
December 31, 2003, 2002 and 2001 were approximately $335,000, $96,000, and
$405,000, respectively.

DEFERRED COMPENSATION PLAN

In late 1997, the Company adopted the Mission Deferred Compensation Plan.
This plan allowed selected employees the option to defer a portion of their
compensation until their retirement or termination. Such deferred compensation
was invested in any one or more of six mutual funds managed by a fund manager at
the direction of the employees. The market value of these investments is
included in current assets at December 31, 2002 and 2001 and was approximately
$419,000, and $124,000, respectively. An equivalent liability due to the plan
participants is included in current liabilities. In June 2003, the Company
terminated the Mission Deferred Compensation Plan, and the fund manager made
final distributions of all funds held in the plan to the plan participants. Both
the current asset and the current liability of approximately $111,000 related to
the plan at the termination date were removed from the Balance Sheet.

STOCK-BASED EMPLOYEE COMPENSATION PLANS

At December 31, 2003, the Company had two stock-based employee compensation
plans, which are described more fully in Note 5. The Company accounts for those
plans under the recognition and measurement principles of APB Opinion No. 25,
Accounting for Stock Issued to Employees, and related Interpretations. No
stock-based employee compensation cost is reflected in net income for options
granted under those plans with an exercise price equal to the market value of
the underlying common stock on the date of the grant. The following table
illustrates the effect on net income and earnings per share if the Company had
applied the fair value recognition provisions of FASB Statement No. 123,
Accounting for Stock-Based Compensation, to stock-based employee compensation
(amounts in thousands, except per share amounts).

MINING VENTURE

During fiscal year 1992, Mission acquired an average 24.4% interest in
three mining ventures (the "Mining Venture") from an unaffiliated individual for
$128,500. At the time of such acquisition, J. P. Bryan, a member of the Mission
Board of Directors until October 2002, his brother, Shelby Bryan and Robert L.
Gerry III (the "Affiliated Group"), owned an average 21.5% interest in the
Mining Venture. Mission's interest in the Mining Venture increased as it paid
costs of the venture while the interest of the Affiliated Group decreased.
Through December 31, 2001, Mission spent an additional $185,000 primarily for
soil evaluations. These exploratory costs, plus $729,000, were charged to
earnings in 2001. Under

58

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

existing agreements Mission is not required to pay any additional mining venture
costs. Should Mission choose to pay any additional costs, they will be charged
directly against income as incurred.

GOODWILL

SFAS No. 142, Goodwill and Other Intangible Assets was approved in June
2001. This pronouncement requires that intangible assets with indefinite lives,
including goodwill, cease being amortized and be evaluated on an annual basis
for impairment. The Company adopted SFAS No. 142 on January 1, 2002 at which
time the Company had unamortized goodwill, related to the Bargo merger, in the
amount of $15.1 million and unamortized identifiable intangible assets in the
amount of $374,300, all subject to the transition provisions. Upon adoption of
SFAS No. 142, $277,000 of workforce intangible assets recorded as unamortized
identifiable assets was subsumed into goodwill and was not amortized as it no
longer qualified as a recognizable intangible asset.

The transition and impairment test for goodwill, effective January 1, 2002,
was performed in the second quarter of 2002. As of January 1, 2002, the
Company's fair value exceeded the carrying amount therefore goodwill was not
impaired. Mission designated December 31st as the date for its annual test.
Based upon the results of such test at December 31, 2002, goodwill was fully
impaired and a write-down of $16.7 million was recorded. The valuation was based
on the following procedures and information:

- computed cash flow model of the Company's oil and gas assets using third
party information and verification;

- applied risking parameters to the various categories of oil and gas
reserves using reputable third party sources for risk profile;

- applied a discount rate to such valuation that approximates Mission's
cost of capital and cost of debt;

- reduced the valuation by Mission's net debt to ascertain the equity fair
value; and

- compared book equity to fair value equity.

The changes in the carrying amount of goodwill for the period ended
December 31, 2002, are as follows (amounts in thousands):

SFAS No. 142 requires disclosure of what reported income before
extraordinary items and net income would have been in all periods presented
exclusive of amortization expense (including any related tax effects) recognized
in those periods related: 1) to goodwill, 2) to intangible assets that are no
longer being amortized, 3) to any deferred credit related to excess over cost 4)
equity method goodwill, and 5) to changes in amortization periods for intangible
assets that will continue to be amortized (including related tax effects).
Similarly adjusted per share amounts are also required to be disclosed for all
periods

59

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

presented. The following table presents the required disclosures concerning
adjusted income for the year ended December 31, 2001 (amounts in thousands,
except per share amounts):

COMPREHENSIVE INCOME

Comprehensive income includes all changes in a company's equity except
those resulting from investments by owners and distributions to owners. The
accumulated balance of other comprehensive income related to cash flow hedges,
net of taxes, is as follows (in thousands):

Balance at January 1, 2001.................................. $ --
Cumulative effect of a change in accounting method.......... (19,328)
Net gains on cash flow hedges............................... 13,919
Reclassification adjustments................................ 14,934
Tax effect on hedge activity................................ (7,239)
--------
Balance at December 31, 2001................................ 2,286
Net gains (losses) on cash flow hedges...................... (341)
Reclassification adjustments................................ (8,323)
Tax effect on hedge activity................................ 2,183
--------
Balance at December 31, 2002................................ (4,195)
Net gains (losses) on cash flow hedges...................... (15,755)
Reclassification adjustments................................ 15,115
Tax effect on hedge activity................................ (748)
--------
Balance at December 31, 2003................................ $ (5,583)
========

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended. This statement
establishes accounting and reporting standards requiring that derivative
instruments (including certain derivative instruments embedded in other
contracts) be recorded at fair value and included in the balance sheet as assets
or liabilities. The accounting for changes in the fair value of a derivative
instrument depends on the intended use of the derivative and the resulting
designation, which is established at the inception of a derivative. Accounting
for qualified hedges allows a derivative's gains and losses to offset related
results on the hedged item in the Consolidated Statement of Operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in Other Comprehensive Income
until the hedged item is recognized in earnings. Hedge effectiveness is measured
at least quarterly based upon the relative changes in fair value between the
derivative contract and the hedged item over time. Any change

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in the fair value resulting from ineffectiveness, as defined by SFAS No. 133, is
recognized immediately in earnings.

ASSET RETIREMENT OBLIGATIONS

In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations, which provided accounting requirements for retirement obligations
associated with tangible long-lived assets. SFAS No. 143 requires that the
Company record a liability for the fair value of its asset retirement
obligation, primarily comprised of its plugging and abandonment liabilities, in
the period in which it is incurred if a reasonable estimate of fair value can be
made. The liability is accreted at the end of each period through charges to
operating expense. The amount of the asset retirement cost is added to the
carrying amount of the related asset and this additional carrying amount is
depreciated over the life of the asset.

The Company adopted the provisions of SFAS No. 143 with a calculation
effective January 1, 2003. The Company's assets are primarily working interests
in producing oil and gas properties and related support facilities. The life of
these assets is generally determined by the estimation of the quantity of oil or
gas reserves available for production and the amount of time such production
should require. The cost of retiring such assets, the asset retirement
obligation, is typically referred to as abandonment costs. The Company hired
independent engineers to provide estimates of current abandonment costs on all
its properties, applied valuation techniques appropriate under SFAS No. 143, and
recorded a net initial asset retirement obligation of $44.3 million on its
Consolidated Balance Sheet. An asset retirement cost of $14.4 million was
simultaneously capitalized in the oil and gas properties section of the
Consolidated Balance Sheet. The adoption of SFAS No. 143 was accounted for as a
change in accounting principle. A $1.7 million charge, net of a $935,000
deferred tax, was recorded to income as a cumulative effect of the change in
accounting principle.

The following table shows changes in the asset retirement obligation that
have occurred in 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes pro forma net income (loss) and net income
(loss) per common share as if the Company had applied the provisions of SFAS No.
143 on January 1, 2001 (amounts in thousands, except per share amounts).

Had the Company applied the provisions of SFAS No. 143 on January 1, 2001,
the Company's asset retirement obligation liabilities as of December 31, 2002
and 2001 would have been $40.3 million and $36.2 million, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statements No. 13 and Technical Corrections, was issued in April 2002. SFAS
No. 145 amends existing guidance on reporting gains and losses on the
extinguishments of debt to prohibit the classification of the gain or loss as
extraordinary, as the use of such extinguishments have become part of the risk
management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to
require sale-leaseback accounting for certain lease modifications that have
economic effects similar to sale-leaseback transactions. The provision of the
Statement related to the rescission of Statement No. 4 is applied in fiscal
years beginning after May 15, 2002. The provisions of Statement related to
Statement No. 13 were effective for transactions occurring after May 15, 2002.
Mission applied the provisions of SFAS No. 145 as they relate to the
extinguishment of debt in accounting for the March 28, 2003 senior subordinated
note repurchase and the December 17, 2003 debt for equity swap which are further
discussed in the notes to consolidated financial statements at footnote 8.

SFAS No. 146, Accounting for Exit or Disposal Activities, was issued in
June 2002. SFAS No. 146 addresses significant issues regarding the recognition,
measurement, and reporting of costs that are associated with exit and disposal
activities, including restructuring activities that are currently accounted for
pursuant to the guidance set forth in EITF Issue No. 94-3, Liability Recognition
of Certain Employee Termination Benefits and Other Costs to Exit an Activity.
SFAS No. 146 is effective for the exit and disposal activities initiated after
December 31, 2002. The Company applied SFAS No. 146 to the closings its offices
located in Longview, Texas and Belleville, Texas. The fields served by these
offices were sold during the fourth quarter of 2003. All activities required to
close the offices and to establish one replacement office nearer to the
Company's remaining operated properties were concluded during 2003. An aggregate
loss of approximately $136,000 was recognized in connection with these office
closings, with almost $122,000 of the total related to severance payments made
in accordance with Mission's existing severance plan. This loss is included in
the interest and other income line of the Statement of Operations.

In November 2002, FASB issued Interpretation No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness to Others, an interpretation of

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No.
34. This interpretation elaborates on the disclosures to be made by a guarantor
in its interim and annual financial statements about its obligations under
guarantees issued. The interpretation also clarifies that a guarantor is
required to recognize, at inception of a guarantee, a liability for the fair
value of the obligation undertaken. The initial recognition and measurement
provisions of the interpretation are applicable to guarantees issued or modified
after December 31, 2002 and did not materially affect our financial statements.
The disclosure requirements are effective for financial statements of interim
and annual periods ending after December 15, 2002 and can be found in the notes
to consolidated financial statements at footnote 12.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment of SFAS No. 123, that
provides alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements. Some of
the disclosure modifications are required for fiscal years ending after December
15, 2002 and are included in these notes to consolidated financial statements at
footnotes 2 and 5.

FASB issued Interpretation No. 46, Consolidation of Variable Interest
Entities, an interpretation of APB No. 51, in January 2003. This interpretation
addresses the consolidation by business enterprises of variable interest
entities as defined in the interpretation. The interpretation applies
immediately to variable interest entities created after January 31, 2003, and to
variable interests in variable interest entities obtained after January 31,
2003. The Company does not own an interest in any variable interest entities;
therefore, this interpretation is not expected to have a material effect on its
financial statements.. The provisions of this interpretation will be applied in
the future should Mission acquire or establish a variable interest entity.

SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities was issued in April 2003. This statement amends and clarifies
the accounting and reporting for derivative instruments, including embedded
derivatives, and for hedging activities under SFAS No. 133. Statement 149 amends
SFAS 133 to reflect the decisions made as part of the Derivatives Implementation
Group (DIG) and in other FASB projects or deliberations. SFAS 149 is effective
for contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The Company has addressed the
pertinent DIG interpretations as they were issued and does not expect that SFAS
No. 149 will have a material impact on the Company's financial statements.

SFAS No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity was issued in May 2003. SFAS No.
150 provides guidance on how to classify and measure certain financial
instruments with characteristics of both liabilities and equity. Many of these
instruments were previously classified as equity. This statement is effective
for financial instruments entered into or modified after May 31, 2003, and
otherwise is effective at the beginning of the first interim period beginning
after June 15, 2003. The statement requires cumulative effect transition for
financial instruments existing at adoption date. None of the Company's financial
instruments were impacted by this statement.

USE OF ESTIMATES

Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities and the disclosure of
contingent assets and liabilities as well as reserve information which affects
the depletion calculation and the computation of the full cost ceiling
limitation to prepare these financial statements in conformity with generally
accepted accounting principles in the United States. Actual results could differ
from these estimates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RECLASSIFICATIONS

Certain reclassifications of prior period statements have been made to
conform to current reporting practices.

3. ACQUISITIONS AND INVESTMENTS

During the last three fiscal years, the Company has completed or made the
following significant acquisitions and investments:

In 2003 spending for oil and gas property acquisitions was approximately
$1.5 million. The most significant individual acquisition was that of an
additional 13.6% interest in High Island 553 for approximately $621,000. We did
not make any significant oil and gas property acquisitions during 2002.

On May 17, 2001, the Company purchased oil and gas properties in south
Louisiana for a gross sales price of $21.5 million.

On May 16, 2001, Bellwether Exploration Company merged with Bargo Energy
Company ("Bargo")and changed its name to Mission Resources Corporation. Under
the merger agreement, Bargo shareholders and option holders received a
combination of cash and Mission common stock. The merger was accounted for using
the purchase method of accounting and was financed through the issuance of $80.0
million, or 9.5 million shares, of Mission common stock to Bargo option holders
and shareholders, and an initial $166.0 million in borrowings under a new credit
facility ("Credit Facility"). Borrowings under the Credit Facility were used as
follows:

- to pay the cash portion of the purchase price to holders of Bargo common
stock and options;

- to pay the amount incurred by Bargo in redeeming its preferred stock
immediately prior to the merger;

- to refinance Bargo's and Bellwether's then-existing credit facilities;
and

- to pay transaction costs.

Initially, the $280.9 million adjusted purchase price allocated to the acquired
assets was $4.1 million to unproved properties, $255.7 million to proved
properties, $1.1 million to current drilling projects, $17.7 million to goodwill
and intangible assets and $2.3 million to current assets, current liabilities
and other non-current assets. The Company also acquired a 10.1% ownership in the
East Texas Salt Water Disposal Company.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

4. RELATED PARTY TRANSACTIONS

Mr. J. P. Bryan, a member of Mission's board of directors until October
2002, was Chairman and CEO of Mission from August 1999 through May 2000. Mr.
Bryan is also Senior Managing Director of Torch Energy Advisors ("Torch") and
owns shares representing 79.5% of the shares of Torch on a fully diluted basis.
Over the past three years Torch has performed services for Mission under various
contracts. The nature of services and amounts of the fees paid to Torch are
summarized in the following table (amounts in thousands).

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

(1) Mission formed its own operations and marketing teams which began performing
these functions in early 2003.

(2) The Snyder gas plant was sold in 2001.

Mission currently uses an Oracle platform provided by P2 Energy Solutions
under a July 2002 hosting agreement. Torch owns 22.2% of P2 Energy Solutions as
the result of a January 15, 2003 merger of its Novistar subsidiary with Paradigm
Technologies, a Petroleum Place company, that created P2 Energy Solutions.
Mission paid hosting fees of $667,000 and $373,000 in the years ended December
31, 2003 and 2002, respectively.

Additionally, sales of oil or natural gas to Torch accounted for
approximately 32% of Mission's fiscal year 2001 oil and gas revenues. Sales to
Torch were not significant in either of fiscal 2003 or 2002.

In July 2002, Mission sold interests in several properties located in New
Mexico to Chisos, LTD ("Chisos"). J.P. Bryan is the President and sole owner of
Chisos. The $4.0 million bid from Chisos exceeded the highest of the three other
bids by $250,000 and provided Mission a non-competition agreement in New Mexico,
a one-year right to participate in developmental drilling and a one-year right
to participate in any preferential rights events. These considerations were not
offered to Mission by any other bidder.

A $250,000 payment under a non-compete agreement was paid in the second
quarter of 2002 to Tim J. Goff, Bargo's former Chief Executive Officer and
former member of Mission's board of directors.

In connection with the reorganization of the Mission's management team in
2002, the Company entered into separation agreements with each of Douglas G.
Manner, Jonathan M. Clarkson, and Daniel P. Foley, on July 31, 2002, September
20, 2002, and November 15, 2002, respectively. Messrs. Manner, Clarkson and
Foley were previously employed by the Company pursuant to employment agreements
that provided for the payment of severance upon separation from the Company
based on multiples of their current salary at the time of separation. The
Company negotiated severance payments for each of Messrs. Manner, Clarkson and
Foley that were considerably less than the amounts provided under their
respective employment agreements. Under the terms of the separation agreements,
the Company paid Messrs. Manner, Clarkson and Foley total payments of $1.3
million, $1.5 million and $450,000, respectively. Of the total $3.3 million,
$250,000 was deferred and was amortized to expense over the term of the
consulting contract and the remainder was charged to general and administrative
expenses in 2002. Messrs. Manner, Clarkson and Foley also surrendered all of
their options or rights to acquire the

65

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's securities. In addition, the Company agreed to provide Messrs. Manner
and Clarkson with certain insurance benefits for up to 24 months after the
separation date, and, to the extent the coverage or benefits received are
taxable to either of Messrs. Manner or Clarkson, the Company agreed to make them
"whole" on a net after-tax basis. Messrs. Manner and Clarkson also agreed to
provide certain consulting services to the Company following their separation
dates. In January 2003, Mr. Manner received a pay out in the sum of $314,852
from the Company's Deferred Compensation Plan made up primarily of deferred
salary and bonuses under the terms of the plan

5. STOCKHOLDERS' EQUITY

COMMON AND PREFERRED STOCK

The Certificate of Incorporation of the Company initially authorized the
issuance of up to 30,000,000 shares of common stock and 1,000,000 shares of
preferred stock, the terms, preferences, rights and restrictions of which are
established by the Board of Directors of the Company. In May 2001, the number of
authorized shares was increased to 60 million shares of common stock and 5
million shares of preferred stock.

Certain restrictions contained in the Company's loan agreements limit the
amount of dividends that may be declared. There is no present plan to pay cash
dividends on common stock as the Company intends to reinvest its cash flows for
continued growth of the Company.

A tax benefit related to the exercise of employee stock options of
approximately $6,000 in 2003 and $240,000 in 2001 was allocated directly to
additional paid in capital. Such benefit was not material in 2002.

On December 17, 2003, the Company entered into a purchase and sale
agreement with FTVIPT -- Franklin Income Securities Fund and Franklin Custodian
Funds -- Income Series providing for the issuance of 4.5 million shares of our
common stock in exchange for the surrender by the Franklin entities of $10.0
million aggregate principal amount of our 10 7/8% senior subordinated notes due
2007. Accrued interest on the notes to the date of the agreement will be paid on
April 1, 2004, the regularly scheduled interest payment date for the notes, or
upon the occurrence of certain other events

On May 16, 2001, Bellwether merged with Bargo Energy Company ("Bargo"). The
resulting company was renamed Mission Resources Corporation. As partial
consideration in the merger, 9.5 million shares of Mission common stock were
issued to the holders of Bargo common stock and options. The $80.0 million
assigned value of such shares was included in the purchase price. Concurrent
with the merger, all Bellwether employees who held stock options were
immediately vested in those options upon closing of the merger. Related to those
options, an additional $102,000 and $799,000 of compensation expense was
recognized in the years ended December 31, 2002 and 2001, respectively, as a
result of staff reductions. The expense was calculated as the excess of the
stock price on the merger date over the exercise price of the option.

SHAREHOLDER RIGHTS PLAN

In September 1997, the Company adopted a shareholder rights plan to protect
Mission's shareholders from coercive or unfair takeover tactics. Under the
shareholder rights plan, each outstanding share of Mission's common stock and
each share of subsequently issued Mission common stock has attached to it one
right. The rights become exercisable if a person or group acquires or announces
an intention to acquire beneficial ownership of 15% or more of the outstanding
shares of common stock without the prior consent of the Company. When the rights
become exercisable each holder of a right will have the right to receive, upon
exercise of the right, a number of shares of common stock of the Company which,
at the time the rights become exercisable, have a market price of two times the
exercise price of the right. The Company
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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

may redeem the rights for $.01 per right at any time before they become
exercisable without shareholder approval. The rights will expire on September
26, 2007, subject to earlier redemption by the board of directors of the
Company.

EARNINGS PER SHARE

The following represents the reconciliation of the numerator (income) and
denominator (shares) of the earnings per share computation to the numerator and
denominator of the diluted earnings per share computation (amounts in thousands,
except per share amounts):

Potentially dilutive options and warrants that are not in the money are
excluded from the computation of diluted earnings per share because to do so
would be antidilutive. For the years ended December 31, 2003, 2002 and 2001, the
potentially dilutive options and warrants excluded represented 1,171,500,
1,050,500 and 2,247,000 shares, respectively.

In periods of loss, the effect of potentially dilutive options and warrants
that are in the money are excluded from the calculation of diluted earnings per
share. For the years ended December 31, 2002 and 2001, potential incremental
shares of 250,000 and 190,000, respectively, were excluded.

TREASURY STOCK

In September 1998, the Company's Board of Directors authorized the
repurchase of up to $5.0 million of the Company's common stock. As of December
31, 2002, 311,000 shares had been acquired at an aggregate price of $1.9
million. In the second quarter of 2003, the number of treasury shares increased
to 389,323 because 78,323 shares were taken into treasury in lieu of collecting
a note receivable valued at approximately $32,000. Treasury shares are valued at
the price at which they are acquired, resulting in approximately $1.9 million
being reported as a reduction to Stockholders' Equity as of December 31, 2003.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK INCENTIVE PLANS

On November 5, 2003, the Compensation Committee of the Board of Directors
awarded Robert L. Cavnar, our Chairman of the Board, President and Chief
Executive Officer, 800,000 share appreciation rights. The rights have an initial
value of $0.55 for each right granted, have a term of ten years and fully vest
only upon the occurrence of a "change of control" or the termination of Mr.
Cavnar's employment by the Company without "cause" or by Mr. Cavnar for "good
reason." Upon the occurrence of any of the foregoing vesting events, the Company
will pay to Mr. Cavnar, for each right, cash in the amount of the difference
between the initial value of the right and the then current price of the
Company's common stock as determined by the share appreciation rights agreement.
Compensation expense will be recorded for this difference at the time it becomes
probable the share appreciation rights will become vested.

The Company has stock option plans that provide for granting of options for
the purchase of common stock to directors, officers and employees of the
Company. In May 2001, the number of shares available for issuance under the 1996
Stock Incentive Plan was increased by 2.0 million. These stock options may be
granted subject to terms ranging from 6 to 10 years at a price equal to the fair
market value of the stock at the date of grant. At December 31, 2003, there were
40,334 options available for grants.

A summary of activity in the stock option plans is set forth below:

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

(1) In 2002, many employees voluntarily surrendered out of the money options.

68

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Detail of stock options outstanding and options exercisable at December 31,
2003 follows:

The estimated weighted average fair value per share of options granted
during 2003, 2002, and 2001 was $2.67, $0.58, and $3.15, respectively. The fair
value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model. The Black-Scholes calculation was calculated
as of yearend for 2001 and 2002, but quarterly for 2003 due to the quarterly
reporting requirements of SFAS No. 148.

The following weighted-average assumptions were used for each calculation.

6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company produces and sells crude oil, natural gas and natural gas
liquids. As a result, its operating results can be significantly affected by
fluctuations in commodity prices caused by changing market forces. The Company
periodically seeks to reduce its exposure to price volatility by hedging a
portion of its production through swaps, options and other commodity derivative
instruments. A combination of options, structured as a collar, is the Company's
preferred hedge instrument because there are no up-front costs and protection is
given against low prices. Such hedges assure that Mission receives NYMEX prices
no lower than the price floor and no higher than the price ceiling. The Company
has also entered into some commodity swaps that fix the NYMEX price to be
received. Hedging activities decreased revenues by $15.8 million, $342,000 and
$13.4 million for the years 2003, 2002 and 2001, respectively.

The Company's 12-month average realized price, excluding hedges, for
natural gas per MCF is generally $0.19 less than the NYMEX MMBTU price. The
Company's 12-month average realized price, excluding hedges, for oil is
generally $0.81 per BBL less than NYMEX. Realized prices differ from NYMEX as a
result of factors such as the location of the property, the heating content of
natural gas and the quality of oil. The oil differential stated above excludes
the impact of Point Pedernales field production for which selling price was
capped at $9.00 per BBL. The Point Pedernales field was sold in March 2003. The
gas differential stated above excludes the impact the Mist field gas production
which is sold at an annually fixed price.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In May 2002, several existing oil collars were cancelled. New swaps and
collars, hedging forecasted oil production were acquired. The Company paid
approximately $3.3 million dollars to counter parties, the fair value of the oil
price collars at that time, in order to cancel the transactions. The
cancellation of these hedges did not have an immediate impact on income. As
required by SFAS No. 133, a $418,000 amount related to the cancelled hedges had
not yet been recognized in earnings. Such amount was amortized from other
comprehensive income ("OCI") over the 19-month life of the cancelled hedges and
has been fully amortized at December 31, 2003 to the interest and other income
line of the Statement of Operations.

In October 2002, the Company elected to de-designate all existing hedges
and to re-designate them by applying the interpretations from the FASB's
Derivative Implementation Group issue G-20 ("DIG G-20"). The Company's previous
approach to assessing ineffectiveness excluded time value which was recorded to
income currently. By using the DIG G-20 approach, because the Company's collars
and swaps meet specific criteria, the time value component is included in the
hedge relationship and is recorded to OCI rather than income which reduces
earnings variability. Both the realized and unrealized gains or losses related
to these de-designated hedges at October 15, 2002 were amortized over the
remaining 15 months to the interest and other income line of the Consolidated
Statement of Operations and were fully amortized at December 31, 2003. Netted
against this amortization was a gain of approximately $193,000 that the Company
recognized in 2003 related to ineffectiveness of its cash flow hedges. As the
existing hedges settle over the next two years, gains or losses in OCI will be
reclassified. The amount expected to be reclassified over the next twelve months
will be an $8.6 million loss.

The following tables detail the cash flow commodity hedges that were in
place at December 31, 2003.

OIL HEDGES

GAS HEDGES

The Company may also enter into financial instruments such as interest rate
swaps to manage the impact of interest rates. Effective September 22, 1998, the
Company entered into an eight and one-half year interest rate swap agreement
with a notional value of $80.0 million. Under the agreement, Mission

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

received a fixed interest rate and paid a floating interest rate. In February
2003, the interest rate swap was cancelled and the Company paid $1.3 million
payment to the counter party.

7. DETERMINATION OF FAIR VALUES OF FINANCIAL INSTRUMENTS

Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The interest rate swap, the commodity derivatives
and the asset retirement obligations are also reflected on the Balance Sheet at
fair value. The following table details the carrying values and approximate fair
values of the Company's other investments and long-term debt at December 31,
2003 and 2002 (in thousands).

8. LONG-TERM DEBT

Long-term debt is comprised of the following at December 31, 2003 and 2002
(in thousands):

Debt maturities by fiscal year are as follows (amounts in thousands):

2004........................................................ $ --
2005........................................................ 80,000
2006........................................................ --
2007........................................................ 117,426
2008........................................................ --
Thereafter.................................................. --
--------
$197,426
========

CREDIT FACILITY

The Company was party to a $150.0 million credit facility with a syndicate
of lenders. The credit facility was a revolving facility, expiring May 16, 2004,
which allowed Mission to borrow, repay and re-borrow under the facility from
time to time. The total amount which might be borrowed under the facility was
limited by the borrowing base periodically set by the lenders based on Mission's
oil and gas reserves and other factors deemed relevant by the lenders. The
facility was re-paid in full on March 28, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On March 28, 2003, simultaneously with the acquisition of $97.6 million of
the 10 7/8% senior subordinated notes, due 2007 (the "Notes") discussed below,
the Company amended and restated its credit facility with new lenders, led by
Farallon Energy Lending, LLC. The entire $947,000 of deferred financing costs
relating to the previously existing facility was charged to earnings as a
reduction in the gain on extinguishment of debt. Under the amended and restated
secured credit agreement (the "Facility"), the Company borrowed $80.0 million
pursuant to term loans (the "Term Loan Facility"), the proceeds of which were
used to acquire approximately $97.6 million face amount of Notes, to pay accrued
interest on the Notes purchased, and to pay closing costs associated therewith.
On June 16, 2003, the Company amended the Facility to add a revolving credit
facility of up to $12.5 million (the "Revolver Facility"), including a letter of
credit sub-facility (the "Sub-Facility") of up to $3.0 million. The Term Loan
Facility expires on January 6, 2005, and the Revolver Facility expires on June
6, 2006. The Facility, which includes the Term Loan Facility and the Revolver
Facility, is secured by a lien on substantially all of the Company's property
and the property of all of the Company's subsidiaries, including a lien on at
least 90% of their respective oil and gas properties and a pledge of the capital
stock of all the subsidiaries.

As of December 31, 2003, the Company had no amounts outstanding under the
Revolver Facility, but has issued $100,000 of letters of credit under the
Sub-Facility. The proceeds of the Revolver Facility are to be used to finance
the Company's ongoing working capital and general corporate needs. Subject to
the terms and conditions of the Revolver Facility, the lenders under the
Revolver Facility have agreed to make advances to the Company, from time to
time, prior to the maturity date of the Revolver Facility, in an amount equal to
the least of the following (in whole multiples of $1,000,000):

(i) $12.5 million minus outstanding letters of credit,

(ii) the Borrowing Base (as defined below) minus outstanding letters
of credit,

(iii) during a Cleanup Period (as defined below), $3.0 million minus
outstanding letters of credit in excess of $1.0 million.

"Borrowing Base" means an amount equal to 10% of the PV-10 Value (as
defined in the Facility) of the Company's proved developed producing reserves
minus the sum of the Bank Product Reserves and Agent Reserves (each as defined
in the Facility). The Borrowing Base was $13.2 million at December 31, 2003. A
"Cleanup Period" shall be either of the following periods if principal amounts
under the Term Loan Facility are outstanding:

(x) the 30-day period immediately following any 90-day period in which
the total of advances and letters of credit outstanding under the Revolver
Facility exceeded $3.0 million for each day, or

(y) the one-day period immediately following any required payment on
any indebtedness subordinate to the Facility.

The interest rate on amounts outstanding under the Term Loan Facility is
12% until February 16, 2004, when it increases to 13% until the Maturity Date.
The interest rate on amounts outstanding under the Revolver Facility will be
equal to the prime rate plus 0.5% per annum, provided that the minimum interest
rate will be 4.75% per annum. Outstanding letters of credit under the
Sub-Facility will be charged a letter of credit fee equal to 3.0% per annum.

The terms of the Term Loan Facility were not materially changed in
connection with the addition of the Revolver Facility and the Sub-Facility,
except that the Company is required to have Excess Availability (as defined
below) of $5.0 million before certain prepayments may be made on the Term Loan
Facility and except for minor modifications to the Company's negative covenants
relating to capital expenditures and consolidated fixed charge coverage ratio.
"Excess Availability" is the amount equal to (i) the lesser of (x) $3.0 million
and (y) the Borrowing Base, plus the Company's cash and cash equivalents subject
to a Cash Management Agreement or a Control Agreement (each as defined in the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Facility) minus (ii) advances under the Revolver Facility plus outstanding
letters of credit plus the Company's trade payables that are 45 days past due
plus the amount of interest payable on the Term Loan Facility and any
indebtedness subordinate to the Facility.

The Facility contains covenants that prevent the Company from making or
committing to make any capital expenditures, except for capital expenditures in
the ordinary course of business which:

- do not exceed the amount approved by the majority lenders for fiscal year
2004; or

- are financed out of the net cash proceeds of issuances of capital stock
(effected during a 30 day period) in excess of $20.0 million or out of
the net cash proceeds of asset sales, with an aggregate limit of $50.0
million during the term of the loans outstanding under the Facility (the
"Loans"), (i) of up to $5.0 million during the term of the Loans, and
(ii) that are paid for the acquisition of replacement assets either 90
days before or 90 days after the asset sale or recovery event.

For fiscal years 2005 and thereafter, the Company cannot make or commit to
make any capital expenditures in excess of the amounts approved by the
administrative agent and the majority lenders.

In addition, the Facility requires that the following financial covenants
be maintained:

- minimum consolidated EBITDA, as of the last day of any fiscal quarter,
for the period of two fiscal quarters that end on such day, of $17.5
million;

- maximum leverage ratio as at the last day of any fiscal quarter beginning
with the fiscal quarter ending June 30, 2003, of 2.75 to 1; and

- minimum consolidated fixed charge coverage ratio, must be at least 1.00
to 1.00 at each fiscal quarter's end on a cumulative basis for the first
eight fiscal quarters. Thereafter the ratio must be at least 1.25 to 1.00
at quarter's end for the total of the four preceding fiscal quarters.

Leverage ratio is defined on the last day of any fiscal quarter as the
ratio of (a) the principal amount of the Loans plus the principal amount of all
indebtedness that is equal to or senior in right of payment to the Loans to (b)
consolidated EBITDA for the period of four quarters ending on such day.
Consolidated fixed charge coverage ratio for any period, is the ratio of: (a)
the consolidated EBITDA during such period plus, for each applicable test period
ended on March 31, June 30, September 30, and December 31, of calendar years
2003 and 2004, $12,000,000 to (b) the sum of (i) the Company's capital
expenditures during such period plus (ii) the Company's cash income tax expense
for such period plus (iii) the Company's cash consolidated interest expense for
such period to the extent paid or required to be paid during such period.

The Facility contains additional covenants that limit Mission's ability,
among other things, to incur additional indebtedness or to create or incur
liens; to merge, consolidate, liquidate, wind-up or dissolve; to dispose of
property; and to pay dividends on or redeem stock. As of December 31, 2003, the
Company was in compliance with the covenants in the Facility.

SENIOR SUBORDINATED NOTES

In April 1997, the Company issued $100.0 million of 10 7/8% senior
subordinated notes due 2007. On May 29, 2001, the Company issued an additional
$125.0 million of senior subordinated notes due 2007 with identical terms to the
notes issued in April 1997 (collectively the "Notes") at a premium of $1.9
million. The premium is amortized as a reduction of interest expense over the
life of the Notes so that the effective interest rate on these additional Notes
is 10.5%. The premium is shown separately on the Balance Sheet. Interest on the
Notes is payable semi-annually on April 1 and October 1. The Notes are
redeemable, in whole or in part, at the option of the Company beginning April 1,
2002 at 105.44%, and decreasing annually to 100.00% on April 1, 2005 and
thereafter, plus accrued and unpaid interest. In the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

event of a change of control of the Company, as defined in the indenture, each
holder of the Notes will have the right to require the Company to repurchase all
or part of such holder's Notes at an offer price in cash equal to 101.0% of the
aggregate principal amount thereof, plus accrued and unpaid interest to the date
of purchase. The Notes contain certain covenants, including limitations on
indebtedness, liens, compliance with requirements of existing indebtedness,
dividends, repurchases of capital stock and other payment restrictions affecting
restricted subsidiaries, issuance and sales of restricted subsidiary stock,
dispositions of proceeds of asset sales and restrictions on mergers and
consolidations or sales of assets. As of December 31, 2003, the Company was in
compliance with its covenants under the Notes.

On March 28, 2003, the Company acquired, in a private transaction with
various funds affiliated with Farallon Capital Management, LLC, pursuant to the
terms of a purchase and sale agreement, approximately $97.6 million in principal
amount of the Notes for approximately $71.7 million, plus accrued interest.
Immediately after the consummation of the purchase and sale agreement, Mission
had $127.4 million in principal amount of Notes outstanding. Including costs of
the transaction and the removal of $2.2 million of previously deferred financing
costs related to the acquired Notes, the Company recognized a $22.4 million gain
on the extinguishment of the Notes.

On December 17, 2003, in a private transaction with FTVIPT -- Franklin
Income Securities Fund and Franklin Custodian Funds -- Income Series, the
Company acquired $10.0 million in principal amount of the Notes in exchange for
4.5 million shares of its common stock. The stock was valued at $1.94 per share,
the opening price for the transaction date. After netting out costs of the
transaction and the removal of previously deferred financing costs and premium
related to the acquired notes, the Company recognized a net gain on the
extinguishment of the Notes of approximately $1.1 million.

9. INCOME TAXES

Income tax expense (benefit) is summarized as follows (in thousands):

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The tax effect of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities at December 31, 2003 and
2002 is as follows (in thousands):

In assessing the realizability of the deferred tax assets, management
considers whether it is more likely than not that some portion or all of the
deferred tax assets will not be realized. The ultimate realization of deferred
tax assets is dependent upon the recognition of future taxable income during the
periods in which those temporary differences are available. Based upon
projections for future state taxable income, management believes it is more
likely than not that the Company will not realize its deferred tax asset related
to state income taxes. In addition, management believes it is more likely than
not that the Company will not realize its deferred tax asset related to the
impairment of the interest in Carpatsky. Accordingly, a valuation allowance has
been recorded in the amount of $5.1 million and $5.3 million for the years
ending December 31, 2003 and 2002, respectively.

A tax benefit related to the cumulative effect of a change in accounting
method of $0.9 million and $1.7 million has been recorded and shown as part of
the cumulative effect on the consolidated statements of operations in 2003 and
2001, respectively.

A tax benefit related to the exercise of employee stock options of
approximately $6,000 and $240,000 was allocated directly to additional paid-in
capital in 2003 and 2001, respectively. Such benefit was not material in 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Total income tax differs from the amount computed by applying the federal
income tax rate to income before income taxes, minority interest, and cumulative
adjustment. The reasons for the differences are as follows:

As previously described, on December 17, 2003, the Company issued 4.5
million shares of common stock in exchange for the surrender of $10 million of
our 10 7/8% senior subordinated notes due 2007. As a result of this transaction,
management believes that the Company has experienced an "ownership change" as
defined in Section 382 of the Internal Revenue Code, which could result in the
imposition of significant limitations on the future use of the Company's
existing net operating loss and tax credit carryforwards in the future. As of
December 31, 2003, management believes that the limitations imposed by Section
382 will not result in the Company being unable to fully utilize it's net
operating loss and tax credit carryforwards to offset future taxable income and
related tax liabilities.

At December 31, 2003, the Company had federal regular tax net operating
loss carryforwards of approximately $91.3 million, which will expire in future
years beginning in 2009 and ending in 2022 as shown below.

10. COMMITMENTS AND CONTINGENCIES

LEASE COMMITMENTS

The Company leases office space for the corporate office in downtown
Houston, Texas. Small field offices are leased in Giddings, Texas and Lafayette,
Louisiana. At December 31, 2003, the minimum future payments under the terms of
the Company's office space operating leases are as follows:

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Rent expense was approximately $700,000, $685,000, and $551,000 in 2003,
2002 and 2001, respectively.

CONTINGENCIES

The Company is involved in litigation relating to claims arising out of its
operations in the normal course of business, including workmen's compensation
claims, tort claims and contractual disputes. Some of the existing known claims
against the Company are covered by insurance subject to limits of such policies
and the payment of deductible amounts. Management believes that the ultimate
disposition of uninsured or unindemnified matters resulting from existing
litigation will not have a material adverse effect on the Company's financial
position, results of operations or cash flows.

A dispute between the Minerals Management Service ("MMS") and the Company
concerning the appropriate expenses to be used in calculating royalties was
resolved in the third quarter of 2002. The Company agreed to pay the MMS
approximately $170,000, which was less than the $1.9 million reserve previously
classified as other liabilities on the Balance Sheet. The Company had reserved
an amount each month assuming that the entire expense tariff being deducted
could be disallowed by the MMS. The Company was able to resolve the dispute on
more favorable terms, resulting in a $1.7 million gain that is included in
interest and other income on the Consolidated Statement of Operations during the
year ended December 31, 2002.

In early 2002, Mission settled for $98,000 Garza Energy Trust, et al. v.
Coastal Oil and Gas Corporation, et al. Mission had accrued $250,000 for the
judgment in 2001, but later arrived at this more favorable settlement.

The Company routinely obtains bonds to cover its obligations to plug and
abandon oil and gas wells. In instances where the Company purchases or sells oil
and gas properties, the parties to the transaction routinely include an
agreement as to who will be responsible for plugging and abandoning any wells on
the property and restoring the surface. In those cases, the Company will obtain
new bonds or release old bonds regarding its plugging and abandonment exposure
based on the terms of the purchase and sale agreement. However, if a party to
the purchase and sale agreement defaults on its obligations to obtain a bond or
otherwise plug and abandon a well or restore the surface or if that party
becomes bankrupt, the landowner, and in some cases the state or federal
regulatory authority, may assert that the Company is obligated to plug the well
since it is in the "chain of title". The Company has been notified of such
claims from landowners and the State of Louisiana and is vigorously asserting
its rights under the applicable purchase and sale agreements to avoid this
liability. At this time, the Company has accrued a liability for approximately
$140,000 for the abandonment and cleanup of the Bayou Ferblanc field and a
$379,000 liability for its proposal to settlement on abandonment issues at the
West Lake Ponchartrain field.

In 1993 and 1996 the Company entered into agreements with surety companies
and with Torch and Nuevo Energy Company ("Nuevo") whereby the surety companies
agreed to issue such bonds to the Company, Torch and/or Nuevo. However, Torch,
Nuevo and the Company agreed to be jointly and severally liable to the surety
company for any liabilities arising under any bonds issued to the Company, Torch
and/or Nuevo. The amount of bonds presently issued to Torch and Nuevo pursuant
to these agreements is approximately $0.4 million and $34.8 million,
respectively. The Company has notified the sureties that it will not be
responsible for any new bonds issued to Torch or Nuevo. However, the sureties
are permitted under these agreements to seek reimbursement from the Company, as
well and from Torch and Nuevo, if the surety makes any payments under the bonds
issued to Torch and Nuevo.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. RESTRUCTURING

During 2001 year the Company took several steps to restructure its
operations and improve its cost structure, including the reduction of staff by
almost 50% and the termination of several outsourcing contracts. The $2.1
million in costs associated with these plans were paid in 2002. In the latter
half of 2002, Mission's Chief Executive Officer, Chief Financial Officer and
Senior Vice President-Finance, left the Company to pursue other activities. This
resulted in a charge of approximately $3.3 million, which is reflected in
general and administrative expenses. As a condition to the separation
agreements, the Company signed agreements with the former Chief Executive
Officer and the former Chief Financial Officer to provide consulting services as
needed over a 12-month period, the cost of which is amortized to expense over
the period.

12. GUARANTEES

The Company's subsidiaries, Mission E&P Limited Partnership, Mission
Holdings LLC, and Black Hawk Oil Company are guarantors under the senior credit
facility and the indenture for the 10 7/8% senior subordinated notes.

In 1993 and 1996 the Company entered into agreements with surety companies
and with Torch and Nuevo whereby the surety companies agreed to issue such bonds
to the Company, Torch and/or Nuevo. However, Torch, Nuevo and the Company agreed
to be jointly and severally liable to the surety company for any liabilities
arising under any bonds issued to the Company, Torch and/or Nuevo. The amount of
bonds presently issued to Torch and Nuevo pursuant to these agreements is
approximately $0.4 million and $34.8 million, respectively. The Company has
notified the sureties that it will not be responsible for any new bonds issued
to Torch or Nuevo. However, the sureties are permitted under these agreements to
seek reimbursement from the Company, as well and from Torch and Nuevo, if the
surety makes any payments under the bonds issued to Torch and Nuevo.

13. SUBSEQUENT EVENTS

On January 30, 2004, Mission closed the $26.6 million acquisition of the
Jalmat field in the Permian Basin of New Mexico. This acquisition adds
approximately 26 BCFE of proved reserves and brings its percentage of natural
gas and NGLs to 59%.

On February 25, 2004, Mission acquired $15.0 million of its 10 7/8% senior
subordinated notes due 2007 for 6.25 million shares of the Company's common
stock. The transaction was completed with Stellar Funding, Ltd., a private
investment fund managed by an affiliate of Guggenheim Capital, LLC. The Company
has also committed to file a registration statement on Form S-3 with the SEC to
register the resale of these shares. We will recognize a gain on the
extinguishment of the notes of approximately $500,000.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. SEGMENT REPORTING

Through mid-2001, the Company's operations are concentrated primarily in
three segments: exploration and production of oil and natural gas in the United
States, in Ecuador and gas plants. The assets in Ecuador and two gas plants were
sold in 2001. The Company did not have any separately reportable segments in the
years 2002 and 2003 as its focus was domestic oil and gas exploration and
production.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

15. SELECTED QUARTERLY FINANCIAL DATA (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE
DATA) (UNAUDITED):

The income in the first quarter of 2003 includes the $22.4 million gain on
the extinguishment of debt related to the purchase and retirement of $97.6
million principal amount 10 7/8% senior subordinated notes due 2007. The loss in
the quarter ended December 31, 2002 includes the impact of a $16.7 million
goodwill impairment.

16. SUPPLEMENTAL INFORMATION -- (UNAUDITED)

OIL AND GAS PRODUCING ACTIVITIES:

Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on estimates
of year-end oil and gas reserve quantities and estimates of future development
costs and production schedules. Reserve quantities and future production are
based primarily upon reserve reports prepared by the independent petroleum
engineering firms. The reserve reports for the year ended December 31, 2001 were
prepared by Ryder Scott Company, Netherland Sewell & Associates, Inc., and T. J.
Smith & Company, Inc. The reserve report for the years ended December 31, 2003
and 2002 were prepared by Netherland Sewell & Associates, Inc.

Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids were made in accordance with SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities." The estimates are based on
prices at year-end. Estimated future cash inflows are reduced by estimated
future development costs (including future abandonment and dismantlement), and
production costs based on year-end cost levels, assuming continuation of
existing economic conditions, and by estimated future income tax expense. Tax
expense is calculated by applying the existing statutory tax rates, including
any known future changes, to the pre-tax net cash flows, less depreciation of
the tax basis of the properties and depletion allowances applicable to the gas,
oil, condensate and NGL production. The impact of the net operating loss is
considered in calculation of tax expense. The results of these disclosures
should not be construed to represent the fair market value of the Company's oil
and gas properties. A market value determination would include many additional
factors including:

(1) anticipated future increases or decreases in oil and gas prices
and production and development costs;

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(2) an allowance for return on investment;

(3) the value of additional reserves not considered proved at the
present, which may be recovered as a result of further exploration and
development activities; and

(4) other business risks.

COSTS INCURRED (IN THOUSANDS)

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

* 2001 total includes $56.6 million of deferred taxes related to the Bargo
merger.

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CAPITALIZED COSTS (IN THOUSANDS):

RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (IN THOUSANDS):

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company's estimated total proved and proved developed reserves of oil
and gas are as follows:

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) The Company's Ecuador reserves were pursuant to a contract with the
Ecuadorian government under which the Company did not own the reserves but
had a contractual right to produce the reserves and receive revenues.

DISCOUNTED FUTURE NET CASH FLOWS (IN THOUSANDS)

The standardized measure of discounted future net cash flows and changes
therein related to proved oil and gas reserves are shown below:

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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands of dollars):

85

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The discounted future cash flows above were calculated using the NYMEX WTI
Cushing price for oil and the NYMEX Henry Hub price for gas that was posted for
the last trading day of each year presented. Those prices were $32.47, $31.17,
and $19.76 per barrel and $5.97, $4.74, and $2.73 per MMBTU, for December 31,
2003, 2002, and 2001, respectively, adjusted to the wellhead to reflect
adjustments for transportation, quality and heating content. The foregoing
discounted future net cash flows do not include the effects of hedging or other
derivative contracts not specific to a property. Including the tax effected
impact of hedging on discounted future net cash flows would have increased
discounted future net cash flows by approximately $5.7 million as of December
31, 2001. Including the tax effected impact of hedging on discounted future cash
flows would have decreased discounted future net cash flows by approximately
$3.4 million and $7.7 million as of December 31, 2003 and 2002.

86

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As of the end of the period covered by this report, Mission's principal
executive officer ("CEO") and principal financial officer ("CFO") carried out an
evaluation of the effectiveness of Mission's disclosure controls and procedures
pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934. Based on
those evaluations, the CEO and CFO believe:

(i) that Mission's disclosure controls and procedures are designed to
ensure that information required to be disclosed by Mission in the reports
it files under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC's
rules and forms, and that such information is accumulated and communicated
to Mission's management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure; and

(ii) that Mission's disclosure controls and procedures are effective.

CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING

There have been no significant changes in Mission's internal controls over
financial reporting during the period covered by this report that has materially
affected, or are reasonably likely to materially affect, Mission's control over
financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2003. Such information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2003. Such information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2003. Such information is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2003. Such information is incorporated herein by reference.

87

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2003. Such information is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. and 2. Financial Statements. See index to Consolidated Financial
Statements and Supplemental Information in Item 8, which information is
incorporated herein by reference.

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

* Filed herewith.

(b) Reports on Form 8-K

(i) The Company filed a Current Report on Form 8-K on October 2, 2003,
relating to the sale of its East Texas properties and updating the
Company's drilling progress.

(ii) The Company filed a Current Report on Form 8-K on November 13,
2003, relating to third quarter 2003 results.

(iii) The Company filed a Current Report on Form 8-K on November 20,
2003, relating to election of a board member.

(iv) The Company filed a Current Report on Form 8-K on December 11,
2003, relating to the Company's hedging arrangements.

(v) The Company filed a Current Report on Form 8-K on December 18,
2003, relating to the exchange of $10,000,000 in aggregate principal amount
of the Company's 10 7/8% Senior Subordinated Notes due 2007 for 4.5 million
shares of the Company's common stock.

90

GLOSSARY OF OIL AND GAS TERMS

TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS

- BBL -- One stock tank barrel, or 42 US gallons liquid volume, of crude
oil or other liquid hydrocarbons.

- BCF -- One billion cubic feet of natural gas.

- BCFE -- One billion cubic feet of natural gas equivalent, converting oil
to gas at the ratio of 1 BBL of oil to 6 MCF of gas.

- BOE -- One barrel of oil equivalent, converting gas to oil at the ratio
of 6 MCF of gas to 1 BBL of oil.

- BTU -- British thermal unit, a measurement of the energy content of
natural gas.

- MBBL -- One thousand Bbls.

- MCF -- One thousand cubic feet of natural gas.

- MCFE -- One thousand cubic feet of natural gas equivalent, converting oil
to gas at a ratio of 1 BBL of oil to 6 MCF of gas.

- MMCF -- One million cubic feet of natural gas.

- MMBTU -- One million British thermal units, a measurement of the energy
content of natural gas.

- MBOE -- One thousand BOE.

- MMBOE -- One million BOE.

TERMS USED TO DESCRIBE THE COMPANY'S INTERESTS IN WELLS AND ACREAGE

- Gross oil and gas wells or acres -- Gross wells or gross acres represent
the total number of wells or acres in which Mission owns a working
interest.

- Net oil and gas wells or acres -- Determined by multiplying "gross" wells
or acres by the working interest that Mission owns in such wells or acres
represented by the underlying properties.

TERMS USED TO ASSIGN A PRESENT VALUE TO THE COMPANY'S RESERVES

- Standard measure of proved reserves -- The present value, discounted at
10%, of the after-tax future net cash flows attributable to estimated net
proved reserves. We calculate this amount by assuming that we will sell
the oil and gas production attributable to the proved reserves estimated
in the independent engineer's reserve report for the prices we received
for the production on the date of the report, unless we had a contract to
sell the production for a different price. We also assume that the cost
to produce the reserves will remain constant at the costs prevailing on
the date of the report. The assumed costs are subtracted from the assumed
revenues resulting in a stream of future net cash flows. Estimated future
income taxes using rates in effect on the date of the report are deducted
from the net cash flow stream. The after-tax cash flows are discounted at
10% to result in the standardized measure of our proved reserves.

- Discounted present value -- The discounted present value of proved
reserves is identical to the standardized measure, except that estimated
future income taxes are not deducted in calculating future net cash
flows. We disclose the discounted present value without deducting
estimated income taxes to provide what we believe is a better basis for
comparison of our reserves to other producers who may have different tax
rates.

91

TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES

- Proved reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering
data, appear with reasonable certainty to be recoverable in the future
from known oil and natural gas reservoirs under existing economic and
operating conditions.

The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2)
of Regulation S-X, is as follows:

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

(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. 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.

(b) 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.

(c) Estimates of proved reserves do not include the following: (1)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (2) crude oil, natural
gas, and natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (3) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and (4)
crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.

- Proved developed reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.

- Proved undeveloped reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required.

TERMS THAT DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES

- Average Reserve to Production Ratio in Years -- A measure of the
productive life of an oil and gas property or a group of oil and gas
properties, expressed in years. Reserve life for the years ended December
31, 2003, 2002 or 2001 equals the estimated net proved reserves
attributable to a property or group of properties divided by production
from the property or group of properties for the four fiscal quarters
preceding the date as of which the proved reserves were estimated.

TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF OUR OIL AND GAS PROPERTIES

- Royalty interest -- A real property interest entitling the owner to
receive a specified portion of the gross proceeds of the sale of oil and
natural gas production or, if the conveyance creating the interest
provides, a specific portion of oil and natural gas produced, without any
deduction for the costs to explore for, develop or produce the oil and
natural gas. A royalty interest owner has no
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right to consent to or approve the operation and development of the
property, while the owners of the working interests have the exclusive
right to exploit the mineral on the land.

- Working interest -- A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, but requiring
the owner of the working interest to bear the cost to explore for,
develop and produce such oil and natural gas. A working interest owner
who owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or disapprove
the appointment of an operator and drilling and other major activities in
connection with the development and operation of a property.

TERMS USED TO DESCRIBE SEISMIC OPERATIONS

- Seismic data -- Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in
exploration for new deposits and to manage or enhance production from
known reservoirs. To gather seismic data, an energy source is used to
send sound waves into the subsurface strata. These waves are reflected
back to the surface by underground formations, where they are detected by
geo-phones that digitize and record the reflected waves. Computers are
then used to process the raw data to develop an image of underground
formations.

- 2-D seismic data -- 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad
area. 2-D seismic data is collected by a single line of energy sources
which reflect seismic waves to a single line of geophones. When
processed, 2-D seismic data produces an image of a single vertical plane
of sub-surface data.

- 3-D seismic -- 3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey
produces a three dimensional image of the subsurface geology by
collecting seismic data along parallel lines and creating a cube of
information that can be divided into various planes, thus improving
visualization. Consequently, 3-D seismic data is a more reliable
indicator of potential oil and natural gas reservoirs in the area
evaluated.

MISCELLANEOUS DEFINITIONS

- Infill drilling -- Infill drilling is the drilling of an additional well
or additional wells in excess of those provided for by a spacing order in
order to more adequately drain a reservoir.

- Upstream oil and gas properties -- Upstream is a term used in describing
operations performed before those at a point of reference. Production is
an upstream operation and marketing is a downstream operation when the
refinery is used as a point of reference. On a gas pipeline, gathering
activities are considered to have ended when gas reaches a central point
for delivery into a single line, and facilities used before this point of
reference are upstream facilities used in gathering, whereas facilities
employed after commingling at the central point and employed to make
ultimate delivery of the gas are downstream facilities.

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SIGNATURES

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

MISSION RESOURCES CORPORATION

By: /s/ ROBERT L. CAVNAR
------------------------------------
Robert L. Cavnar
Chairman and Chief Executive Officer

Date: March 10, 2004

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

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INDEX TO EXHIBITS

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* Filed herewith.