MISSION RESOURCES CORP - 10-K Annual Report

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

FORM 10-K

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. Yes [X]

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

The aggregate market value of the voting stock held by non-affiliates of
the registrant at June 30, 2004 was approximately $136,522,433.

As of March 7, 2005, the number of outstanding shares of the registrant's
common stock was 41,530,671.

Documents Incorporated by Reference: Portions of the registrant's annual
proxy statement, to be filed within 120 days after December 31, 2004, are
incorporated by reference into Part III of this Form 10-K.
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MISSION RESOURCES CORPORATION AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2004

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, 2004, our estimated net proved reserves, using constant prices that
were in effect at such date, were 93 billion cubic feet ("BCF") of natural gas,
43 billion cubic feet equivalents ("BCFE") of natural gas liquids ("NGLs") and
15 million barrels ("MMBBL") of oil, for total reserves of approximately
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226 BCFE. Approximately 60% of our estimated net proved reserves were natural
gas or NGLs, and approximately 78% were developed at December 31, 2004.

OUR BUSINESS STRATEGY AND COMPETITIVE STRENGTHS

In July 2004, we announced that we were evaluating strategic alternatives
to enhance stockholder value. This process involved: a comprehensive review of
the existing asset base and opportunity set; an assessment of the commodities,
transactions, debt and equity markets; and an evaluation of our strengths and
challenges in the current environment.

The conclusions reached when this evaluation was completed in September
2004 were as follows:

- Our existing asset base remains under-exploited.

- We have a multitude of internal opportunities for value creation.

- Potential exists to acquire desirable assets in our core areas.

- Debt and equity capital is available to us, if needed, to finance
attractive growth opportunities.

- Our team is highly qualified and deeply committed to creating stockholder
value in a disciplined fashion.

Mission's action plan as a result of these conclusions is to:

EXPAND THE EXPLORATION PROGRAM IN OUR CORE AREAS -- We have increased our
exploration budget to $20 million for 2005, a 132% increase over the $8.6
million spent in 2004. Our exploratory prospects are located primarily in the
Gulf Coast onshore area in well-established tertiary producing trends. Through
February 2005, we have drilled two successful exploratory wells in Texas: the
Weise #1, a Lower Wilcox gas discovery located in Goliad County, and the Iles #1
located in Jefferson County in the Yegua formation. Our first offset well to the
Weise #1, the Dehnert #1, also found pay in the Lower Wilcox zone. We are
currently drilling three additional offset wells targeting the Lower Wilcox: the
Weise #2, the Simmons #1 and the Buckner Foundation #1. One additional location
is scheduled to be drilled in the second quarter of 2005. In addition to
development wells around our new discoveries, we have scheduled five exploratory
prospects for drilling later this year. Three of these are in our Lower Wilcox
core area of the central Texas gulf coast, one is an Upper Wilcox
stratigraphic/structure play in south Texas and one is a Frio prospect in
Brazoria County, Texas.

AGGRESSIVELY PURSUE ACQUISITIONS OF PRODUCING PROPERTIES -- We are actively
seeking to purchase producing properties with additional upside potential. With
the purchase of producing properties, we expect to receive benefits from
economies of scale, increased operational control and reduced production
volatility as individual wells become a smaller percentage of a larger
production base. This strategy will enable us to have more predictable
production and reduce our per unit expenses. We are continuing to evaluate
transactions that could substantially increase proved reserves. Such
acquisitions might be within existing core areas or could create one or more new
core areas. Our strategy is for any acquisition to be accretive to cash flow.

HEDGE AS APPROPRIATE TO PROTECT OUR INVESTMENTS -- We will continue to hedge at
least 50% of our current proved developed production to ensure our cash flow is
adequate to service our debt, make our planned capital expenditures and provide
an appropriate return on capital. With a significant acquisition, we would
consider increasing this percentage to fix returns for the capital we invested.

CONTINUE TO DIVEST NON-CORE PROPERTIES FOR GOOD VALUE -- We will continue to
optimize our portfolio by divesting non-core properties at favorable prices.
Over time, our intent is to divest high operating cost properties or properties
that are outside of our core areas.

EXPAND BANK FACILITIES AS NEEDED WHILE MAINTAINING DISCIPLINE IN OUR CAPITAL
STRUCTURE -- Our previously stated long-term goal is to lower our ratio of debt
to total capitalization to below 50%. Although we may borrow funds to finance a
specific acquisition, and thus temporarily increase that ratio, we intend to
utilize

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equity to maintain discipline in our capital structure. We currently have a $150
million universal shelf registration in place that increases our ability and
flexibility to meet capital needs. As we add reserves through the drill bit or
through acquisitions, we expect to expand our bank facilities.

MAINTAIN AN OPPORTUNISTIC POSTURE -- We will continue to dedicate the human
resources and capital to enable us to move quickly when opportunity arises.

OUR OIL AND GAS PROPERTIES

RESERVES

Our estimated net proved oil and gas reserves at December 31, 2004 were
approximately 226 BCFE. In 2004 we more than replaced production through reserve
additions and extensions. Also, as part of our strategy to reduce unit costs and
increase our percentage of production from natural gas, we acquired the Jalmat
field, which added approximately 34.3 BCFE of low operating cost natural gas
reserves. Set forth below is a reconciliation of our year-end 2004 reserves, as
compared to our year-end 2003 reserves, based upon the evaluation of reserves by
Netherland, Sewell & Associates, Inc., our independent reservoir engineering
firm. The reserves were calculated using year-end pricing required by the
Securities and Exchange Commission ("SEC"):

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 SEC, 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. The estimates include the effects of hedges
in place at December 31, 2004. 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

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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.

PRODUCTION

The following table sets forth our net production and net proved reserves
as of and for the year ended December 31, 2004 by geographic area.

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(1) In accordance with SEC 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, 2004 for natural gas and oil used in our
estimate were $6.18 per MMBTU and $43.33 per BBL, respectively.

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

See Note 15 of the Notes to Consolidated Financial Statements for data
relating to production volumes, production costs and oil and gas reserve
information.

The following table provides summary statistics about our most significant
properties by geographic area as of December 31, 2004.

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(1) Calculated by dividing total proved reserves for the field by 2004
production for the field.

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

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PERMIAN BASIN AREA

Waddell Ranch Field

Waddell Ranch field is a large, mature property consisting of 900 producing
wells and 300 injection wells. Productive formations range in depth from the
Queen formation at 3,000 feet to the Ellenburger formation at 15,000 feet. This
property, which covers over 75,000 acres, is located in the Permian Basin in
Crane County, Texas. Burlington Resources Inc. is the operator and Mission's
interest is approximately 10%. This field has had gross cumulative production of
1.4 trillion cubic feet ("TCF") of natural gas and 422 million barrels of oil. A
portion of this field is under waterflood. This field is under continuous
development through recompletions, workovers, and new drills.

Jalmat Field

Mission is the operator and holds an approximate 95% working interest in
the Jalmat field, located in the Permian Basin in Lea County, New Mexico. The
field consists of 140 producing wells with production 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 for the extraction of NGL's. Numerous behind pipe
recompletions and infill drilling potential exist in both of the Yates and
7-Rivers formations. Additionally, the deeper Queen formation may have
waterflood potential.

TXL North Unit

The TXL North Unit is an active waterflood unit that consists of 260 wells
and produces from the Clearfork Tubb formation at a depth of approximately 5,600
feet. Anadarko Petroleum Corporation operates this property, located in the
Permian Basin in Ector County, Texas. Mission holds an approximate 20% working
interest and 25% net revenue interest. This field is currently on a 10-acre
infill program with 48 successful new wells drilled in 2004 with continued
drilling expected in 2005.

Goldsmith Field

The Goldsmith field consists primarily of the CA Goldsmith Unit, operated
by XTO Energy Inc., and is located in the Permian Basin in Ector County, Texas.
Mission holds a 25% working and net revenue interest in this unit. 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. Development
plans for 2005 include five new drill wells in the Clearfork formation.

Wasson Field

Mission holds an approximate 37% working interest in the Brahaney Unit in
the Wasson field, located in the Permian Basin in Yoakum County, Texas. Apache
Corporation operates this waterflood unit that consists of 90 producing wells
and produces from the San Andres formation at a depth of approximately 5,200
feet. Production has increased significantly in past few years as a result of a
successful infill drilling program. In 2004, seven new wells were drilled and
the development drilling program continues with nine wells planned for 2005.

GULF COAST AREA

South Bayou Boeuf Field

South Bayou Boeuf field is located in Lafourche Parish, Louisiana and
produces from multiple Miocene-age reservoirs at depths ranging from 10,000 to
12,500 feet. One well was drilled in 2004. Multiple development drilling
opportunities exist in other sands in the field. Mission is the operator of the
field with an average working interest of 96% in seven producing wells.

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Second Bayou Field

Second Bayou field is located in Cameron Parish, Louisiana. The field
produces oil from shallow Miocene-age reservoirs at 5,500 feet and gas from deep
Miocene-age reservoirs below 10,000 feet. Mission operates three of the six
producing wells and holds an average working interest of 55% in four oil wells
and two gas wells.

Reddell Field

Reddell field is located in Evangeline Parish, Louisiana and produces from
the Upper, Middle and Lower Wilcox formations at depths ranging from 10,000 to
13,000 feet. Burlington Resources Inc. is the operator of the field consisting
of 16 producing wells. In 2004, four wells were drilled with additional
development drilling planned for 2005. Mission holds a 15% working interest in
the field.

GULF OF MEXICO AREA

High Island Block A-553

Mission owns approximately a 37% working interest and is the operator in
this property located in federal waters offshore Texas in 260 feet of water. The
block contains one platform with seven wells. The seventh well was recently
drilled and is being completed. Production is primarily gas with liquid
condensate from the Pleistocene and Pliocene formations at depths ranging from
5,000 to 12,000 feet. One additional well is planned for 2005 with more drilling
available in future years.

South Marsh Island Block 142

This property is located in federal waters offshore Louisiana at a depth of
230 feet. Hunt Petroleum Inc. operates 16 wells on two platforms that produce
from the Pleistocene and Pliocene formations at depths ranging from 3,000 to
7,000 feet. Mission owns a 31% working interest. Two successful wells were
drilled in 2004 and additional drilling is planned. 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,
South Texas and in the Gulf of Mexico. The following tables set forth the
results of drilling activity for the last three years:

Six wells were in progress as of December 31, 2004.

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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, 2004. 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, 2004. 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, 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 2004 and 2003, sales of oil and natural gas to Shell Trading (US)
Company accounted for approximately 26.4% and 21.5% of our oil and gas revenues,
respectively. In 2004, sales of oil and natural gas to Conoco Phillips Company
accounted for approximately 12.0% of our oil and gas revenues. No other
purchaser accounted for more than 10% of our oil and gas revenues in 2004, 2003
or 2002. If we were to lose any one (including Shell Trading (US) Company or
Conoco Phillips 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. 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 oil and gas companies 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. In the fourth quarter of 2004, we began to experience delays in
drilling at three of our fields due to delays of contracted drilling rigs and
reduced availability for new rigs due to the current increased level
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of demand throughout our industry. We are unable to predict when, or if, the
drilling rig shortages will abate or other such shortages may again occur or how
they would affect exploration and exploitation plans.

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 successfully for these properties.

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.

Mission's sale of natural gas is generally made at the market prices at the
time of sale. Therefore, even though the Company sells significant volumes to
major purchasers, the Company believes other purchasers would be willing to buy
the Company's natural gas at comparable market prices.

Natural gas continues to supply a significant portion of North America's
energy needs and the Company believes the importance of natural gas in meeting
this energy need will continue. The tightening of natural gas supply and demand
fundamentals has resulted in extremely volatile natural gas prices, which is
expected to continue.

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 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,
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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.

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.

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.
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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, some of which may be 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.

Equipment used in the exploration and production of oil and gas may become
contaminated with naturally-occurring radioactive material ("NORM") at levels
subject to state regulation. Among other things, state regulations require
identification of oilfield equipment with NORM levels in excess of specified
thresholds, impose worker protection standards, regulate disposal and provide
penalties for violations. Mission is subject to such regulatory requirements
governing NORM, such regulations may become more stringent and related costs may
increase.

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
12

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 the Oil Pollution Act of 1990 ("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 pollutants into state
waters. In the event of an unauthorized discharge, Mission may be liable for
penalties and costs.

Oil Pollution Act

The 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.

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.
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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 EPA 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.

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 preliminary title review of local mineral records. We do
conduct title investigations and often obtain a title opinion and curative work
is performed with respect to significant defects, if any, 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.

14

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 85%
of our properties are pledged as collateral under our senior secured credit
facility.

OUR EMPLOYEES

At December 31, 2004, Mission had 91 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 we have a good relationship
with our employees. None of our employees are 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 30,000 square feet of leased
office space at 1331 Lamar, Suite 1455, Houston, Texas 77010. We also have
leased offices in Giddings, Texas, Lafayette, Louisiana and Eunice, New Mexico
from which our employees supervise local oil and gas operations.

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.

15

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 $88.1 million, $35.4 million,
and $21.4 million for the years ended December 31, 2004, 2003 and 2002,
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.
Using estimated prices of $35.00 per BBL and $5.50 per MMBTU, we have budgeted
total capital expenditures in 2005 of $71 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 a significant portion of our future exploration
and development requirements will provide us with the flexibility and liquidity
to meet our planned capital requirements for 2005. 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 2005 exploration and
development program. A reduction in our borrowing base could be the result of
lower pricing or production, inability to drill or unfavorable drilling results,
changes in oil and gas reserve engineering, our lenders' inability to agree to
an adequate borrowing base, or adverse changes in our lenders' practices
regarding estimation of reserves. 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.

Our capital structure consists of our outstanding 9 7/8% senior notes due
2011 (the "9 7/8% Notes"), our $50.0 million senior secured revolving credit
facility and our $25.0 million second lien term loan facility. Although all of
our current debt is at lower interest rates than the 10 7/8% senior subordinated
notes due 2007 (the "10 7/8% Notes") that were outstanding at December 31, 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 $15
million to $17 million in 2005, 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
senior secured revolving credit facility and $25.0 million term loan
facility, require us to meet certain financial tests, and other
restrictions, including restrictions with respect to our 9 7/8 Notes,
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;

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

- we may have a higher level of debt than some of our competitors, which
may put us at a competitive disadvantage;

- we may be more vulnerable to economic downturns and adverse developments
in our industry (especially declines in oil and natural gas prices) or
the economy in general; and
16

- our level of indebtedness could limit our flexibility in planning for, or
reacting to, changes in our business and the industry in which we
operate.

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, 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 may incur additional indebtedness, which may intensify the risks described
above, including our ability to service our indebtedness.

We may incur additional indebtedness. Although the indenture governing our
9 7/8% Notes contains restrictions on our incurrence of additional indebtedness,
these restrictions are subject to a number of qualifications and exceptions, and
under certain circumstances, indebtedness incurred in compliance with these
restrictions could be substantial. Also, these restrictions do not prevent us
from incurring obligations that do not constitute indebtedness. To the extent
new indebtedness is added to our current indebtedness levels, the risks
described above could substantially increase.

To service our indebtedness, we will require a significant amount of cash. Our
ability to generate cash depends on many factors beyond our control, and any
failure to meet our debt obligations could harm our business, financial
condition and results of operations.

Our ability to make payments on and to refinance our indebtedness and to
fund planned capital expenditures will depend on our ability to generate cash
from operations in the future. This, to a certain extent, is subject to general
economic, financial, competitive, legislative, regulatory and other factors that
are beyond our control, including the prices that we receive for oil and natural
gas.

We cannot assure you that our business will generate sufficient cash flow
from operations or that future borrowings will be available to us under our new
senior secured revolving credit facility in an amount sufficient to enable us to
pay our indebtedness or to fund our other liquidity needs. If our cash flow and
capital resources are insufficient to fund our debt obligations, we may be
forced to sell assets, seek additional equity or debt capital or restructure our
debt. We cannot assure you that any of these remedies could, if necessary, be
effected on commercially reasonable terms, or at all. In addition, any failure
to make scheduled payments of interest and principal on our outstanding
indebtedness would likely result in a reduction of our credit rating, which
could harm our ability to incur additional indebtedness on acceptable terms. Our
cash flow and capital resources may be insufficient for payment of interest on
and principal of our debt in the future and any such alternative measures may be
unsuccessful or may not permit us to meet scheduled debt service obligations,
which could cause us to default on our obligations and could impair our
liquidity.

Restrictive debt covenants could limit our growth and our ability to finance
our operations, fund our capital needs, respond to changing conditions and
engage in other business activities that may be in our best interests.

Our senior secured revolving credit facility, our second lien term loan and
the indenture governing our 9 7/8% Notes contain a number of significant
covenants that, among other things, restrict our ability to:

- dispose of assets;

- incur or guarantee additional indebtedness and issue certain types of
preferred stock;

- pay dividends on our capital stock;

- create liens on our assets;

- enter into sale and leaseback transactions;

17

- enter into specified investments or acquisitions;

- repurchase, redeem or retire our capital stock or subordinated debt;

- merge or consolidate, or transfer all or substantially all of our assets
and the assets of our subsidiaries;

- engage in specified transactions with affiliates; or

- other corporate activities.

Also, our senior secured revolving credit facility and our second lien term
loan require us to maintain compliance with specified financial ratios and
satisfy certain financial condition tests. Our ability to comply with these
ratios and financial condition tests may be affected by events beyond our
control, and we cannot assure you that we will meet these ratios and financial
condition tests. These financial ratio restrictions and financial condition
tests could limit our ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the economy in
general or otherwise conduct necessary corporate activities. We may also be
prevented from taking advantage of business opportunities that arise because of
the limitations that the restrictive covenants under our new senior secured
revolving credit facility, our new second lien term loan facility and the
indenture governing our 9 7/8% Notes impose on us.

A breach of any of these covenants or our inability to comply with the
required financial ratios or financial condition tests could result in a default
under our senior secured revolving credit facility, our second lien term loan
and our 9 7/8% Notes. A default, if not cured or waived, could result in
acceleration of all of our secured indebtedness and our 9 7/8% Notes. The
accelerated debt would become immediately due and payable. If that should occur,
we may not be able to pay all such debt or to borrow sufficient funds to
refinance it. Even if new financing were then available, it may not be on terms
that are acceptable to us.

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 senior secured revolving 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.

18

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, 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 full cost 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 or that such hedges will be available on acceptable conditions.

We may not be able to market all of 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.

19

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% per annum, 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.

20

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. Approximately $181,000, $252,000 and
$161,000 in costs were recognized for the abandonment and cleanup of the Bayou
Ferblanc field for the years ended December 31, 2004, 2003 and 2002,
respectively. Approximately $379,000 in costs were recognized for the proposed
settlement of abandonment issues at the West Ponchartrain field in 2003. 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 Nuevo pursuant to these agreements is approximately $34.3 million. Torch
currently has no bonds outstanding pursuant to these agreements. 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. Effective May
17, 2004, Plains Exploration and Production Company acquired Nuevo Energy
Company.

21

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 "Applicable Laws and Regulations -- United States 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, Marshall L.
Munsell, our Senior Vice President -- Land and Land Administration and Thomas C.
Langford, our Senior Vice President -- General Counsel. 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

22

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

As protection against financial loss resulting from these operating
hazards, we maintain insurance coverage, including certain physical damage,
employer's liability, comprehensive general liability and worker's compensation
insurance. Although we are not insured against all risks in all aspects of our
business, such as political risk and risk of major terrorist attacks, we believe
that the coverage we maintain, including business interruption insurance on our
major revenue producing fields, is customary for companies engaged in similar
operations. The occurrence of a significant event against which we are not fully
insured could have a material adverse effect on our financial position.

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

As of December 31, 2004, we do not operate wells that represent
approximately 55% 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.

23

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
under our effective shelf registration statement or otherwise, 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 7.2 million
shares of common stock for issuance under outstanding options, all of which are
registered for resale on currently effective registration statements. In
addition, we have registered the resale of 16.75 million shares of common stock
that were issued in exchange for $40 million of our 10 7/8% Notes, and 312,000
shares of common stock issued in connection with the offering of our 9 7/8%
Notes.

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 9 7/8% Notes. In addition, our senior
secured revolving credit facility and our second lien term loan contain
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

24

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 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 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, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES

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 -- Financial Condition -- Financing and Note 8 of the
Notes to Consolidated Financial Statements). There were approximately 1,051
stockholders of record as of February 28, 2005.

25

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).

26

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 2004 included the following financial and operational highlights.

- Acquired approximately 34.3 BCFE at the Jalmat field, located in the
Permian Basin in New Mexico.

- Redeemed our 10 7/8% Notes and issued $130.0 million of new 9 7/8% Notes.

- Established a new senior secured revolving credit facility, making
available $30.0 million for short-term borrowings and an additional $20.0
million for acquisitions.

- Entered into a new $25.0 million second lien term loan.

- Reduced long-term debt by $28.5 million and interest expense by $6
million for the year ended December 31, 2004 as compared to the same
period in 2003.

- Reduced operating expenses per MCFE 15.4% from $1.43 for the year ended
December 31, 2003 to $1.21 for the year ended December 31, 2004.

- Drilled 66 successful developmental wells and one successful exploratory
well that increased reserves enough to fully replace 2004 production.

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

- Hedged over 50% of 2005 proved developed producing reserves at a weighted
average floor price of $31.21 per BBL and $5.02 per MMBTU, with
additional hedges on 2006 production.

- Doubled ownership interest in the Chocolate Bayou, Southwest Lake Boeuf,
Backridge and West Lake Verret fields by acquiring approximately 6 BCFE
of reserves.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2004 COMPARED TO YEAR ENDED DECEMBER 31, 2003

Net Income/Loss -- Net income for the year ended December 31, 2004 was $2.9
million, or $0.07 per share on a diluted basis, while the net income for the
year ended December 31, 2003 was $2.4 million, or $0.10 per share on a diluted
basis. In 2003, our purchase and retirement of $107.6 million principal amount
of our 10 7/8% Notes generated a $23.5 million gain, $15.3 million net of tax,
on the extinguishment of debt. In 2004, our repurchase and retirement of the
remaining $117.4 million principal amount of our 10 7/8% Notes, along with other
debt refinancing costs, generated a net loss of $2.6 million, $1.7 million net
of taxes. Absent the debt extinguishment gains and (losses), net income (loss)
for the years ended December 31, 2004 and 2003, would have been $4.6 million and
($12.9) million, respectively. See "Financial Condition-Financing" section below
for additional information about the debt retirement transactions. The $17.5
million improvement, net of debt extinguishment, in the twelve month period
ended December 31, 2004 resulted from increased gas production, higher oil and
gas prices and lower interest and lease operating expenses. This was partially
offset by a $4.1 million non-cash increase in G&A expense ($2.6 million, net of
taxes) from the issuance, to our Chairman and CEO, of stock options to replace
stock appreciation rights.

27

Oil and Gas Revenues -- Oil and gas revenues were $128.7 million in the year
ended December 31, 2004, compared to $99.3 million for the respective period in
2003. 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 sale of the East Texas and Raccoon Bend fields in the last half and
fourth quarter of 2003, respectively, are the primary causes for the 21.5%
decline in oil production. Gas production, however, increased 37.8%, more than
offsetting the oil production decline and resulted in a combined MMCFE increase
of 5.2%. The primary reasons for the gas increase are the January and April 2004
acquisitions of the Jalmat field in Lea County, New Mexico. The Jalmat
acquisition, along with production increases from the LeBlanc #1 well in
Vermilion Parish, Louisiana, the South Marsh Island A-11 and C-5 wells, offshore
Louisiana, and the High Island 553 A-7 recompletion, offshore Texas, account for
most of the production increase.

Increased pre-hedge oil and gas prices averaged $39.88 per Bbl and $5.89
per MCF or 34.3% and 15.0% higher, respectively, in the twelve month period
ended December 31, 2004 compared to $29.69 per Bbl and $5.12 per MCF in the same
period of 2003. Realized oil and gas prices, including the effect of hedges,
were $4.93 per Bbl and $1.06 per MCF higher, respectively, for the year ended
December 31, 2004, as compared to the same period in 2003. Several factors,
including instability in the Middle East, lower inventories and a cold winter
contributed to the commodity price increases.

28

Costs of Oil and Gas Production -- In addition to analyzing gross changes in
costs, management finds it useful to look at certain 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) Taxes other than income and transportation costs relate to specific fields
or production, therefore analysis of such costs per unit of total production
is not useful.

Total lease operating expenses for the year 2004 decreased 11% from 2003
levels, and decreased 15.4% on a per MCFE basis. Production increases along with
lease operating expense decreases contributed to the per MCFE cost decrease. In
gross dollars, the most significant cost reductions related to the sale of high
cost properties and subsequent redeployment of proceeds into lower cost gas
properties. The cost per MCFE of the East Cameron and East Texas fields sold in
August 2003, and the Raccoon Bend oil field sold in the fourth quarter of 2003,
were significantly higher than the cost per MCFE of the Jalmat field, which was
purchased in the first quarter of 2004. In the second quarter of 2004, we
recovered approximately $575,000 of previously paid Waddell Ranch field lease
operating expenses as a result of in-house review of billable costs. Exclusive
of this recovery, recurring lease operating expense on an MCFE basis was $1.23
for the twelve months ending December 31, 2004 as compared to $1.43 for the
twelve months ending December 31, 2003. In the fourth quarter of 2004, our lease
operating expense increased for two reasons. First, workovers are being
performed due to near-record high commodity prices that probably would not have
been performed in the past, and second, the cost of basic oil field services has
increased. We expect these trends to continue into 2005.

Production taxes, depending upon the jurisdiction, are calculated using a
percentage of revenue or a per-unit of production rate. In general, production
taxes increase as revenue and production increase. In 2004, the 32.7% increase
in production taxes was disporportionately larger than our revenue increase
because Louisiana's tax rate on natural gas increased by 40%.

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 resulted in the property tax
reduction in 2004. Assessed values are based upon beginning of the year reserves
and the previous year's average realized price. As a result of the sale of Texas
properties late in 2003, and their replacement with properties in New Mexico, a
state with lower property taxes than Texas, our property taxes have been reduced
by 19.2%.

Depreciation, depletion and amortization ("DD&A") is 14.8% higher for the
twelve months ended December 31, 2004 over the same period in 2003. This
increase is due to a 9.1% higher DD&A rate and a 5.2% increase in production on
an MCFE basis, discussed under Oil and Gas Revenues above. The DD&A rate is
calculated by dividing the net property costs plus future development costs, by
the remaining BOE

29

of reserves. The $0.15 increase in DD&A on a per MCFE basis reflects the impact
of a $40.0 million increase in future development costs. The effect of this
increase to the depletable base was mitigated by an increase in reserves as a
result of the Jalmat acquisition in January and April 2004 and reserve additions
described in our December 31, 2004 reserve report prepared by Netherland, Sewell
and Associates, Inc.

Asset Retirement Obligation Accretion Expense -- 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 -- Federal and state income taxes for the year ended December 31,
2004 were based upon a 37.4% effective tax rate which represented a change from
the 36.5% effective tax rate of 2003. The effective rate is calculated by
dividing income tax provision by net income before taxes. There was a $3.9
million valuation allowance on deferred taxes applicable at December 31, 2004.
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 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 are available. Based upon the currently
available evidence, management believes it is more likely than not that a) the
Company will not realize the deferred tax benefit associated with its interest
in the Carpatsky production payment and b) a portion of the Company's state
income tax loss carryforwards will not be utilized.

Interest and Other Income -- Interest and other income decreased $1.6 million
from a net gain of $1.1 million reported for the year 2003 to a net loss of
$461,000 reported for the year 2004. 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 $1.0 million net gain from hedge
ineffectiveness was recorded in 2003 while a net gain of $0.1 million was
recorded in 2004. Other factors contributing to the decrease in interest and
other income; include, $361,000 of equity in the earnings of White Shoal
Pipeline Corporation in 2003 compared to $53,000 in 2004 and bad debt recoveries
of $109,000 in 2003 compared to bad debt expense of $441,000, in 2004.

Interest and Related Expenses -- Interest expense decreased 22.7% to $19.8
million for the year ended December 31, 2004 from $25.6 million for the year
ended December 31, 2003. 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 and was not replaced.
Throughout 2003 and in early 2004, we repurchased approximately $137.6 million
in 10 7/8% Notes. On May 10, 2004, the remaining $87.4 million of 10 7/8% Notes
were redeemed. The redemption of all the 10 7/8% Notes and subsequent issuance
of the 9 7/8% Notes resulted in a significant reduction in interest paid for the
year ended December 31, 2004 as compared to the same period in 2003. Also,
throughout 2003 and early 2004 interest expense on the term loan was based on an
$80 million principal balance at 12% interest. On April 8, 2004, as part of the
debt refinancing, the principal balance on the term loan was repaid and replaced
with a senior secured revolving credit facility and a second lien term loan with
a combined balance of $40 million and interest rates between 3.1% and 7.6%. This
decrease in balance and interest

30

rates resulted in a reduction in interest paid for the year ended December 31,
2004, as compared to the same period in 2003.

General and Administrative Expenses -- General and administrative expenses
totaled approximately $16.9 million in the year ended December 31, 2004 and
$10.9 million in the year ended December 31, 2003. This increase is primarily
the result of the recognition of a non-cash compensation expense of $4.1 million
from the issuance of stock options to replace stock appreciation rights. The
options were granted with a strike price of $0.55 per share, which is the same
exercise price as the surrendered stock appreciation rights. As a result of
these options having an exercise price below the market value for Mission's
common stock, we were required to recognize this non-cash expense. An increase
in separation costs of $0.4 million along with additional costs relating to
Sarbanes-Oxley Act compliance of approximately $0.5 million also accounted for a
portion of the increase. A general increase in staffing during the twelve month
period ended December 31, 2004 has contributed to higher salaries and benefits
than that of the same period in 2003.

Some costs incurred in 2004 are not expected to be recurring. The non-cash
compensation expense and separation costs are considered one-time events. While
many of these costs are not expected to reoccur in 2005, our total general and
administrative expenses are anticipated to remain near 2004 levels as headcount
in 2005 goes up. Salaries and benefits will increase and public company expenses
will continue to rise as the Company increases in size.

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 our 10 7/8 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. Absent the debt extinguishment
in 2003 and goodwill impairment in 2002, net loss for these years would have
been $12.9 million and $21.8 million, respectively.

31

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 completed 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 was small, but continued production from these projects benefited
our 2004 results. In addition, 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.

Costs of Oil and Gas Production -- In addition to analyzing gross changes in
costs, management finds it useful to look at certain 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).

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% Notes and their replacement with an $80.0 million term loan facility
bearing interest at 12% 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.

Certain costs incurred in 2003 were 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.

FINANCIAL CONDITION

CAPITAL STRUCTURE

In 2004 we reduced our indebtedness by $28.5 million lowering our interest
expense in 2005 to approximately $15 to $17 million. This was accomplished by
taking the following steps in the first half of 2004:

- The issuance of 16.75 million shares of common stock in exchange for $40
million of the 10 7/8% Notes in three transactions in December 2003,
February 2004 and March 2004.

- The issuance of $130 million of the 9 7/8% Notes, and the simultaneous
establishment of a new senior secured revolving credit facility and a new
second lien term loan.

- The redemption of the remaining $87.4 million aggregate principal amount
of the 10 7/8% Notes at a premium using a portion of the proceeds from
the issuance of the 9 7/8% Notes.

- The repayment in full of the prior term loan facility using the remaining
portion of the proceeds from the issuance of the 9 7/8% Notes, together
with $21.5 million that was advanced under the new senior secured
revolving credit facility and $25 million that was borrowed under the new
second lien term loan.

Interest expense remains a significant use of cash that reduces the cash
available for the exploration and development of oil and gas properties.

34

FINANCING

Our outstanding indebtedness totaled $170 million at December 31, 2004. The
nature of our indebtedness as of December 31, 2004 and December 31, 2003 is
summarized on the table below (amounts in thousands).

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

(1) Amounts available for borrowing at December 31, 2004 and 2003 under the
revolving credit facilities were $34.9 million and $12.5 million,
respectively.

On April 8, 2004, we issued senior notes, announced the redemption of our
10 7/8% Notes and replaced both our revolving credit facility and term loan.
Those transactions and the details of the resulting debt are discussed below.

9 7/8% Notes

On April 8, 2004, we issued $130.0 million of our 9 7/8% Notes which are
guaranteed on an unsubordinated, unsecured basis by all of our current
subsidiaries. Interest on the notes is payable semi-annually, on each April 1
and October 1, commencing on October 1, 2004.

A portion of the net proceeds from the offering of the 9 7/8% Notes was set
aside to redeem, on May 10, 2004, the $87.4 million aggregate principal amount
of the 10 7/8% Notes that remained outstanding. On April 8, 2004, the remainder
of the net proceeds from the offering of the 9 7/8% Notes, together with $21.5
million that was advanced under the new senior secured revolving credit facility
(as described below) and $25.0 million that was borrowed under the new second
lien term loan (as described below), was used to completely discharge all of our
outstanding indebtedness under our prior revolving credit facility and term
loan.

At any time on or after April 9, 2005 and prior to April 9, 2008, we may
redeem up to 35% of the aggregate original principal amount of the 9 7/8% Notes,
using the net proceeds of equity offerings, at a redemption price equal to
109.875% of the principal amount of the 9 7/8% Notes, plus accrued and unpaid
interest. On or after April 9, 2008, we may redeem all or a portion of the
9 7/8% Notes at the redemption prices (expressed as percentages of principal
amount) set forth below plus accrued and unpaid interest, if redeemed during the
twelve-month period beginning on April 9 of the years indicated below:

If we experience specific kinds of change of control, we may be required to
purchase all or part of the 9 7/8% Notes at a price equal to 101% of the
principal amount together with accrued and unpaid interest.

35

The 9 7/8% Notes contain covenants that, subject to certain exceptions and
qualifications, limit our ability and the ability of certain of our subsidiaries
to:

- incur additional indebtedness or issue certain types of preferred stock
or redeemable stock; transfer or sell assets;

- enter into sale and leaseback transactions;

- pay dividends or make other distributions on stock, redeem stock or
redeem subordinated debt;

- enter into transactions with affiliates;

- create liens on our assets;

- guarantee other indebtedness;

- enter into agreements that restrict dividends from subsidiaries;

- make investments;

- sell capital stock of subsidiaries; and

- merge or consolidate.

Standard and Poor's and Moody's currently publish debt ratings for the
9 7/8% Notes. Their ratings consider a number of items including our debt
levels, planned asset sales, near-term and long-term production growth
opportunities, capital allocation challenges and commodity price levels.
Standard & Poor's rating on the 9 7/8% Notes is "CCC" and Moody's rating is
"Caa2." A decline in credit ratings will not create a default or other
unfavorable change in the 9 7/8% Notes.

Senior Secured Revolving Credit Facility

On April 8, 2004, we entered into a senior secured revolving credit
facility led by Wells Fargo Bank, N.A. The facility, which matures on April 8,
2007, is secured by a first priority mortgage and security interest in at least
85% of our oil and gas properties, all of the ownership interests of all of our
subsidiaries, and our equipment, accounts receivable, inventory, contract
rights, general intangibles and other assets. The facility is also guaranteed by
all of our subsidiaries.

Availability under the facility, which includes a $3 million subfacility
for standby letters of credit, is subject to a borrowing base that is determined
at the sole discretion of the facility lenders. The initial borrowing base of
the facility was $50 million, of which $30 million was available for general
corporate purposes and $20 million was available for the acquisition of oil and
gas properties approved by the lenders. The borrowing base is redetermined on
each April 1 and October 1. Mission and the lenders each have the option to
request one unscheduled interim redetermination between scheduled
redetermination dates. On October 1, 2004, it was determined that there would be
no change in the borrowing base.

On April 8, 2004, we were advanced $21.5 million under the facility, which
amount, together with a portion of the net proceeds from the offering of the
9 7/8% Notes and $25 million that was borrowed under a second lien term loan (as
described below), was used to completely discharge all of our outstanding
indebtedness under our prior revolving credit facility and term loan. At
December 31, 2004, $15.0 million in borrowings were outstanding and $34.9
million was available for borrowing ($20.0 million of which is restricted to the
acquisition of oil and gas properties approved by the lenders).

Advances under the facility bear interest, at our option, at either (i) a
margin (which varies from 25.0 basis points to 125.0 basis points based upon
utilization of the borrowing base) over the base rate, which is the higher of
(a) Wells Fargo's prime rate in effect on that day, and (b) the federal funds
rate in effect on that day as announced by the Federal Reserve Bank of New York,
plus 0.5%; or (ii) a margin (which varies from 175.0 basis points to 275.0 basis
points based upon utilization of the borrowing base) over LIBOR. We are allowed
to prepay any base rate or LIBOR loan without penalty, provided that each

36

prepayment is at least $500,000 and multiples of $100,000 in excess thereof,
plus accrued and unpaid interest.

Standby letters of credit may be issued under the $3 million letter of
credit subfacility. We are required to pay, to the issuer of the letter of
credit, with respect to each issued letter of credit, (i) a per annum letter of
credit fee equal to the LIBOR margin then in effect multiplied by the face
amount of such letter of credit plus (ii) an issuing fee of the greater of $500
or 12.5 basis points.

The facility requires us to hedge forward, on a rolling 12-month basis, at
least 50% of proved producing volumes projected to be produced over the
following 12 months. We are also required to hedge forward, on a rolling
12-month basis, 25% of proved producing volumes projected to be produced over
the succeeding 12-month period. Any time that we have borrowings under the
facility in excess of 70% of the borrowing base available for general corporate
purposes, the agent under the facility may require us to hedge an additional
percentage of projected production volumes on terms acceptable to the agent.

The facility also contains the following restrictions on hedging
arrangements and interest rate agreements: (i) the hedge provider must be a
lender under the facility or an unsecured counterparty acceptable to the agent
under the facility; and (ii) total notional volume must be not more than 75% of
scheduled proved producing net production quantities in any period or, with
respect to interest rate agreements, notional principal amount must not exceed
75% of outstanding loans, including future reductions in the borrowing base.

The facility contains the following covenants which are considered
important to our operations. At December, 31, 2004, we were in compliance with
each of the following covenants:

- Maintain a current ratio of consolidated current assets (as defined in
the facility) to consolidated current liabilities (as defined in the
facility) of not less than 1.0 to 1.0;

- Maintain (on an annualized basis until the passing of four fiscal
quarters and thereafter on a rolling four quarter basis) an interest
coverage ratio (as defined in the facility) of no less than (i) 2.50 for
June 30, 2004 through December 31, 2004, (ii) 2.75 for March 31, 2005
through June 30, 2005, and (iii) 3.0 for September 30, 2005 and
thereafter;

- Maintain (on an annualized basis until the passing of four fiscal
quarters and thereafter on a rolling four quarter basis) a leverage ratio
(as defined in the facility) of no more than 3.5 for December 31, 2004
and thereafter; and

- Maintain a tangible net worth (as defined in the facility) of not less
than 85% of tangible net worth at March 31, 2004, plus 50% of positive
net income after tax distributions, plus 100% of equity offerings after
March 31, 2004, excluding any asset impairment charges.

The facility also includes restrictions with respect to changes in the
nature of our business; sale of all or a substantial or material part of our
assets; mergers, acquisitions, reorganizations and recapitalizations; liens;
guarantees; debt; leases; dividends and other distributions; investments; debt
prepayments; sale-leasebacks; capital expenditures; lease expenditures; and
transactions with affiliates.

Second Lien Term Loan

On April 8, 2004, we entered into a second lien term loan with a syndicate
of lenders arranged by Guggenheim Corporate Funding, LLC. The loan, which
matures on April 8, 2008, is secured by a second priority security interest in
the assets securing the senior secured revolving credit facility. The facility
is also guaranteed by all of our subsidiaries. On April 8, 2004, we borrowed the
$25.0 million under the loan, which amount, together with a portion of the net
proceeds from the offering of the 9 7/8% Notes and $21.5 million borrowed under
the senior secured revolving credit facility (as described above), was used to
completely discharge all of the outstanding indebtedness under the prior
revolving credit facility and term loan.

37

The loan accrues interest in each monthly interest period at the rate of
30-day LIBOR plus 525 basis points per annum, payable monthly in cash. We may
prepay the loan at any time after the date six months and one day after April 8,
2004 in whole or in part in multiples of $1 million at the prices (expressed as
percentages of principal amount) set forth below, plus accrued and unpaid
interest, if prepaid during each successive 12-month period beginning on April
9th of each year indicated below:

Provided, however, that no prepayment shall be made prior to the date six months
and one day after April 8, 2004.

The loan contains covenants that are no more restrictive than those
contained in the senior secured revolving credit facility.

Redeemed 10 7/8% Notes

In April 1997, we issued $100 million of 10 7/8% Notes due 2007. On May 29,
2001, we issued an additional $125 million of 10 7/8% Notes with identical terms
to the notes issued in April 1997 at a premium of $1.9 million. The premium,
shown separately on the Consolidated Balance Sheet, was amortized as a reduction
of interest expense over the life of the 10 7/8% Notes so that the effective
interest rate on the additional 10 7/8% Notes was 10.5%. Interest on the 10 7/8%
Notes was payable semi-annually on April 1 and October 1.

On March 28, 2003, we acquired, in a private transaction with various funds
affiliated with Farallon Capital Management, LLC, approximately $97.6 million in
principal amount of the 10 7/8% Notes for approximately $71.7 million, plus
accrued interest. Including costs of the transaction and the removal of $2.2
million of previously deferred financing costs related to the acquired 10 7/8%
Notes, we recognized a $22.4 million gain on the extinguishment of the 10 7/8%
Notes.

In December 2003, February 2004 and March 2004, in three private
transactions, we acquired $40.0 million aggregate principal amount of the 10
7/8% Notes in exchange for an aggregate of 16.75 million shares of our common
stock as summarized below.

On May 10, 2004, the remaining $87.4 million of 10 7/8% Notes were redeemed
at a premium of approximately $1.6 million. This premium is included in the $4.1
million ($2.6 million, net of tax) net loss on extinguishment of debt reported
in the three month period ended June 30, 2004.

Former Credit Facilities

We were 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 us to borrow, repay and re-borrow under the

38

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 our oil and gas reserves and other factors deemed relevant by the lenders.
The facility was re-paid in full and cancelled on March 28, 2003.

On March 28, 2003, simultaneously with the acquisition of $97.6 million in
principal amount of the 10 7/8% Notes, we amended and restated the credit
facility with new lenders, led by Farallon Energy Lending, LLC. Deferred
financing costs of $947,000 relating to the previously existing facility were
charged to earnings as a reduction in the gain on extinguishment of debt. Under
the amended and restated facility, we borrowed $80.0 million, the proceeds of
which were used to acquire approximately $97.6 million face amount of 10 7/8%
Notes, to pay accrued interest on the 10 7/8% Notes purchased, and to pay
closing costs. The amended and restated facility was cancelled in April 2004 and
was replaced by the "Senior Secured Revolving Credit Facility" discussed above.

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, 2004, we had negative working capital of $10.3 million
compared to positive working capital of $16.3 million at December 31, 2003.
However, our 2003 working capital was positively impacted by approximately $24.9
million of the proceeds from 2003 property sales that 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. If this cash held
for reinvestment was excluded from the December 31, 2003 working capital, our
working capital would have been a negative $8.6 million at that date. The
unfavorable impact of increased commodity prices on the recorded commodity
derivative liability balance was a significant factor in our working capital
position in both 2004 and 2003. The 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. The
short-term liability was $10.5 million and $8.6 million at December 31, 2004 and
2003, respectively. Since these amounts 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.

Other working capital components included accrued revenues that increased
$3.8 million from December 31, 2003 to December 31, 2004 mainly due to higher
commodity prices. Higher production volumes as a result of the Jalmat
acquisition in the first half of 2004 also had an impact on the increase in
accrued revenues. Almost offsetting the $3.8 million increase in accrued
revenues was a $4.1 million increase in accrued liabilities between the periods.
Royalties payable accounts for most of this increase. The increase in royalties
payable included approximately $3.2 million of royalties that are awaiting
completion of title opinions. Upon receipt of the title opinions and executed
division orders, Mission will be required to make payment. This payable may
increase as the well produces or decrease as title opinions are completed and
royalties paid.

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 2005. Our senior secured revolving
credit facility is also available for short-term borrowings.

Source of Capital: Operations

Cash flow provided by operating activities totaled $58.7 million, $18.9
million, and $7.2 million for the fiscal years 2004, 2003, and 2002,
respectively. Our operating cash flow is sensitive to many variables, with
prices of oil, natural gas and NGLs being the most volatile. Prices are
determined primarily by prevailing market conditions. Regional and worldwide
economic growth, weather and other variable factors influence
39

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

On April 8, 2004, we issued $130 million of 9 7/8 Notes due 2011, announced
the redemption of our 10 7/8% senior subordinated notes due 2007, and replaced
both our revolving credit facility and term loan

Our outstanding balance under the 9 7/8% Notes was 130.0 million at
December 31, 2004. Our outstanding balance under the 10 7/8% Notes was $117.4
million at December 31, 2003 and was $225.0 million at December 31, 2002. A
portion of the net proceeds from the offering of the 9 7/8% Notes was used, on
May 10, 2004, to redeem the $87.4 million aggregate principal amount of the
10 7/8% Notes that remained outstanding. On April 8, 2004, the remainder of the
net proceeds from the offering of the 9 7/8% Notes, together with $21.5 million
that was advanced under the new senior secured revolving credit facility (as
described below) and $25.0 million that was borrowed under the new second lien
term loan (as described below), was used to completely discharge all of our
outstanding indebtedness under the prior revolving credit facility and term
loan.

Borrowings under our new senior secured revolving credit facility were
$15.0 million at December 31, 2004, and $34.9 million was available for
borrowing. There were no borrowings outstanding under our old credit facilities
at December 31, 2003 and 2002. Availability under the new revolving credit
facility, which includes a $3 million subfacility for standby letters of credit,
is subject to a borrowing base that is determined at the sole discretion of the
facility lenders. The initial borrowing base of the facility was $50 million, of
which $30 million was available for general corporate purposes and $20 million
was available for the acquisition of oil and gas properties approved by the
lenders. The borrowing base is redetermined on each April 1 and October 1.
Mission and the lenders each have the option to request one unscheduled interim
redetermination between scheduled redetermination dates. On October 1, 2004, it
was determined that there would be no change in the borrowing base.

Our outstanding balance under the second lien term loan was $25.0 million
at December 31, 2004. Our outstanding balance was $80.0 million in first lien
term loans at December 31, 2003. There were no term loans outstanding at
December 31, 2002. On April 8, 2004, we borrowed the $25.0 million under the
second lien term loan, which amount, together with a portion of the net proceeds
from the offering of the 9 7/8% Notes and $21.5 million borrowed under the
senior secured revolving credit facility, was used to completely discharge all
of the outstanding indebtedness under the prior revolving credit facility and
term loan.

As previously discussed under "Financing," both our 9 7/8% Notes and our
senior secured revolving credit facility contain covenants limiting our
activities or requiring that we maintain specific financial ratios. As of
December 31, 2004, we were in compliance with all applicable covenants.
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

40

amount value of the 10 7/8% Notes. In February 2004, we acquired $15.0 million
of our 10 7/8% Notes due 2007 for 6.25 million shares of common stock in a
transaction with Stellar Funding, Ltd. On March 15, 2004, we acquired an
additional $15 million of our 10 7/8% Notes due 2007 from Harbert Distressed
Investment Master Fund, Ltd. in exchange for 6.0 million shares of common stock.
These shares of common stock were registered for resale under an effective
registration statement.

On April 8, 2004, we issued 312,000 shares of our common stock in lieu of
cash to our financial advisors as a fee for services rendered during the debt
refinancing previously discussed under "Financing." The $1.2 million fair value
of this consideration was recorded as deferred financing costs.

On August 4, 2004, the Compensation Committee of Mission's Board of
Directors granted to Robert L. Cavnar, Chairman, President and CEO of Mission, a
nonqualified option to acquire 800,000 shares of our common stock. We granted
this option to replace the grant of 800,000 share appreciation rights made to
Mr. Cavnar in November 2003. The option was granted under the 2004 Incentive
Plan, has a term of 10 years, is fully vested and has a strike price of $0.55
per share, which is the same exercise price as the surrendered share
appreciation rights. As a result of this option having an exercise price below
the market value for our common stock at the time of issuance, we recognized a
non-cash compensation expense of approximately $4.1 million ($2.6 million, net
of tax) in the third quarter of 2004.

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 in 2004, 2003 and 2002 were
approximately $13.0 million, $28.1 million, and $60.4 million, respectively. Net
proceeds are gross proceeds adjusted for transaction costs and interim
operations.

Use of Capital: Exploration and Development

Mission's expenditures for exploration, including land and seismic costs,
and development of domestic oil and gas properties totaled $45.4 million, $33.4
million, and $20.6 million for the fiscal years 2004, 2003, and 2002,
respectively.

Our capital budget for 2005 is $71 million using estimated prices of $35.00
per BBL and $5.50 per MMBTU. Approximately 54% of the total is planned for
development projects, while 28% is planned for exploration. The remaining 18% 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 2005. Our intent is to apply less than
our discretionary cash flow to capital projects in 2005. The budget may be
modified throughout the year based on our projections of cash flow; however, due
to the timing of our capital programs, we may spend more than our cash flow in
individual quarters.

Use of Capital: Acquisitions and Other Corporate Assets

In 2004, spending for oil and gas property acquisitions was approximately
$41.5 million. The purchase of a 94.5% working interest in the Jalmat field for
$30.2 million along with the purchase of additional working interests in the
Chocolate Bayou, Southwest Lake Boeuf, Backridge and West Lake Verret fields for
approximately $11 million accounted for all of the 2004 property acquisitions.
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.

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

41

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.

We invested approximately $1.2 million in other corporate assets during
2004. The majority of this investment went towards the purchase and
implementation of an upgraded revenue and general accounting system. 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.

Use of Capital: Contractual Obligations and Commercial Commitments

The tables below illustrate our significant contractual obligations and
other commercial commitments as of December 31, 2004 (amounts in thousands):

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

* Includes principal and interest.

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 and asset retirement cost, 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 34% and 38% of our total oil and gas revenues in the years ended
December 31, 2004 and 2003 respectively. Any reduction in proved reserves
without a corresponding reduction in capitalized costs will increase the
depletion rate. If during 2005, our reserves increase by 10%, our depletion per
MCFE would decrease approximately $0.16, or 9%; however, a 10% decrease in
reserves will have a 11% impact, increasing depletion per MCFE by approximately
$0.19.

42

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, 2004, 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, 2004
were $43.33 per barrel and $6.18 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, 2004 been
10% lower, we would have been 76% 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

43

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 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 payable or a receivable, as appropriate,
should be recorded equal to the net value of the imbalance. As of December 31,
2004, we had recorded a net liability of approximately $850,000, representing
approximately 500,000 MCF at an average price of $1.70 per MCF, related to
imbalances on properties at or nearing depletion. The net liability accrued as
of December 31, 2003, was $1.1 million, representing approximately 379,000 MCF
at an average price of $2.95 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), our unrecorded imbalance, valued at current prices would
be approximately a $593,000 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 estimated asset retirement costs for all of our assets as of such date,
inflation adjusted those costs to the forecast abandonment date, discounted that
amount back to the date we acquired the asset and recorded an asset retirement
liability in that amount with a corresponding addition to our asset value. Then
we computed all depletion previously taken on future plugging and abandonment
costs, and reversed that depletion. Finally, we accreted the liability to
present day and computed historical depletion on the new asset retirement cost
through the adoption date. Any income effect of this initial implementation was
reflected as a change in accounting method on our Statement of Operations.

44

After initial implementation, we reduce the liability as abandonment costs
are incurred. As new wells are drilled or purchased their initial asset
retirement cost and liability will be calculated and recorded. Should either the
estimated life or the estimated abandonment costs of a property change upon our
quarterly 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 risk-adjusted rate. The
risk-adjusted rate is re-evaluated annually so the liability could have layers
of valuation. We accrete the liability in these layers using the appropriate
period and interest 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; therefore, abandonment costs will
almost always approximate the estimate. We have developed a process through
which to track and monitor the obligations for each asset.

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 $3.5 million credit that is in our full cost
pool for 2004 would be included in income.

As with previously discussed estimates, the estimation of our initial
liability and its subsequent remeasurements are 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 use the remaining estimated useful
life from the year-end 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 for our
NOLs. If we estimate that some or all of our NOLs 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 NOLs 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").

45

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, our estimation of the
future benefit of our NOLs is dependent upon many variables and is subject to
change. Management's judgment on these variables considers, in part, the input
of qualified third parties when possible. To assist in the determination of the
impact (if any) that the 382 Limitations may have upon the Company's NOLs, we
have used information derived from a) the public equity markets b) data provided
by an independent reserve engineering firm and c) opinions from an independent
appraisal firm. 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

NEW ACCOUNTING PRONOUNCEMENTS

Staff Accounting Bulletin ("SAB") No. 106, regarding the application of
FASB Statement No. 143, Accounting for Asset Retirement Obligations, by oil and
gas producing companies following the full cost accounting method was issued in
September 2004. SAB 106 provided an interpretation of how a company, after
adopting Statement 143, should compute the full cost ceiling to avoid
double-counting the expected future cash outflows associated with asset
retirement costs. The provisions of this interpretation have been applied by the
Company and has no impact on the financial statements.

SFAS No. 123R, Share-Based Payments was issued in December 2004. SFAS No.
123R requires public companies to measure the cost of employee services in
exchange for an award of equity instruments based on a grant-date fair value of
the award (with limited exceptions), and that cost must generally be recognized
over the vesting period. SFAS No. 123R amends the original SFAS No. 123 and 95
that had allowed companies to choose between expensing stock options or showing
pro forma disclosure only. SFAS No. 123R becomes effective as of the beginning
of the first interim or annual reporting period that begins after June 15, 2005.
The impact of SFAS No. 123R is dependent upon grants issued and; therefore,
cannot be estimated at this time.

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 12-month average realized price, excluding hedges, for natural gas was
$0.12 per MCF less than the NYMEX MMBTU price. Our 12-month realized price,
excluding hedges, for oil was $1.47 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 gas differential
stated above excludes the impact of the Mist field gas production, which is sold
at an annually fixed price.

46

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, 2004 prices, our cash flows
would decrease by $11.9 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 7, 2005.

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

Our senior secured revolving credit facility and term loan have floating
interest rates and as such expose us to interest rate risk. If interest rates
were to increase 10% over their current levels, and at our current level of
borrowing, our annualized interest expense would increase $258,000 or 1.7%. We
have considered, but have not yet entered into, derivative transactions designed
to mitigate interest rate risk.

The Company paid $1.3 million in February 2003 to cancel an interest rate
swap under which Mission received a fixed interest rate and paid a floating
interest rate. The swap originated in 1998 and had a notional value of $80
million.

47

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

48

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Mission Resources Corporation:

We have audited the accompanying consolidated balance sheets of Mission
Resources Corporation and subsidiaries as of December 31, 2004 and 2003, and the
related consolidated statements of operations, changes in stockholders' equity
and comprehensive income or loss, and cash flows for each of the years in the
three-year period ended December 31, 2004. 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 the standards of the Public
Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2004, in conformity with U.S. generally
accepted accounting principles.

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.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of Mission
Resources Corporation's internal control over financial reporting as of December
31, 2004, based on criteria established in Internal Control -- Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 7, 2005 expressed an unqualified
opinion on management's assessment of, and the effective operation of, internal
control over financial reporting.

KPMG LLP

Houston, Texas
March 7, 2005

49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Mission Resources Corporation:

We have audited management's assessment, included in the accompanying
report, "Management's Annual Report on Internal Controls over Financial
Reporting", that Mission Resources Corporation and subsidiaries maintained
effective internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal Control -- Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Mission Resources Corporation's management is responsible for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting. Our
responsibility is to express an opinion on management's assessment and an
opinion on the effectiveness of the Company's internal control over financial
reporting based on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Mission Resources Corporation
and subsidiaries maintained effective internal control over financial reporting
as of December 31, 2004, is fairly stated, in all material respects, based on
criteria established in Internal Control -- Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also,
in our opinion, Mission Resources Corporation and subsidiaries maintained, in
all material respects, effective internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).

50

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Mission Resources Corporation and subsidiaries as of December 31, 2004
and 2003, and the related consolidated statements of operations, changes in
stockholders' equity and comprehensive income or loss, and cash flows for each
of the years in the three-year period ended December 31, 2004, and our report
dated March 7, 2005 expressed an unqualified opinion on those consolidated
financial statements.

KPMG LLP

Houston, Texas
March 7, 2005

51

MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROLS
OVER FINANCIAL REPORTING

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

Management of Mission Resources Corporation (the "Company") is responsible
for establishing and maintaining effective internal control over financial
reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of
1934.

The Company's internal control over financial reporting is a process
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. The Company's internal
control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the Company;
(2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the Company are
being made only in accordance with authorizations of management and board of
directors of the Company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the Company's assets that could have a material effect on the financial
statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of the Company's internal control
over financial reporting as of December 31, 2004. In making this assessment,
management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal
Control -- Integrated Framework. As a result of this assessment, management
believes that the Company's internal control over financial reporting as of
December 31, 2004 is effective, based on those criteria.

KPMG LLP, the independent registered public accounting firm who also
audited the Company's consolidated financial statements, has issued an
attestation report on management's assessment of the effectiveness of internal
control over financial reporting as of December 31, 2004. KPMG's attestation
report on management's assessment of the Company's internal control over
financial reporting appears on page 52 hereof.

Management
Mission Resources Corporation

Houston, Texas
March 7, 2005

52

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to Consolidated Financial Statements.
53

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS -- (CONTINUED)

See Notes to Consolidated Financial Statements.
54

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See Notes to Consolidated Financial Statements.
55

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

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

See Notes to Consolidated Financial Statements.
56

MISSION RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Notes to Consolidated Financial Statements.
57

MISSION RESOURCES CORPORATION

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 net investment of approximately $237,000 at December
31, 2004 is included in the other assets line of the Consolidated Balance Sheet.
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.

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,
landmen and engineers directly involved in acquisition, exploration and
development activities, and amounted to $2.1 million, $1.8 million, and $1.3
million in the years ended December 31, 2004, 2003 and 2002, respectively

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. Depletion expense per thousand cubic feet
of gas equivalent ("MCFE") was approximately $1.80 in 2004, $1.65 in 2003, and
$1.29 in 2002.

58

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Unproved Property Costs -- 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. 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, 2004.
This category of costs will transfer into the full cost pool in 2005.

Approximately $1.2 million, $2.8 million, and $2.2 million were evaluated
and moved to the full cost pool in 2004, 2003 and 2002, 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 $13.0 million, $28.1 million and $60.4 million
were recorded as adjustments to net capitalized costs during the years 2004,
2003 and 2002, 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, 2004 were $43.33 per barrel
of oil (NYMEX WTI Cushing) and $6.18 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 $11.0 million because prices prevailing at
December 31, 2004 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, 2004 and 2003; therefore no
impairment was required.

59

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

ROYALTIES PAYABLE

The accrued liabilities line of the Consolidated Balance Sheet includes
approximately $3.2 million of royalties that are awaiting completion of title
opinions. Upon receipt of the title opinions and executed division orders,
Mission will be required to make payment. This liability may increase in size as
the well produces or decrease as title opinions are completed and royalties
paid. Typically, royalties are paid within one to two months after the
production is sold.

REVENUE RECOGNITION AND GAS IMBALANCES

Revenues are recognized and accrued as production occurs. In 2002, no one
customer accounted for greater than 10% of oil and gas revenues. In 2003 and
2004, sales to Shell Trading (US) Company totaled approximately $19.7 million
and $35.7 million, respectively, and accounted for 21.5% and 26.4%,
respectively, of the Company's oil and gas revenues exclusive of the impact of
hedges. Also in 2004, sales to Conoco Phillips Company totaled approximately
$16.2 million and accounted for 12.0% of the Company's oil and gas revenue
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 attributable to a
property have depleted to the point that there are insufficient reserves to
satisfy existing imbalance positions. Then a payable or a receivable, as
appropriate, is recorded equal to the net value of the imbalance. As of December
31, 2004, the Company had recorded a net liability of approximately $850,000,
representing approximately 500,000 MCF at an average price of $1.70 per MCF,
related to imbalances on properties at or nearing depletion. The net liability
accrued as of December 31, 2003, was approximately $1.1 million for
approximately 379,000 MCF at an average price of $2.95 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 approximately a $593,000
liability.

RECEIVABLES

The Company records receivables at their net realizable value with specific
write off of receivables that are not deemed to be collectible. Joint interest
billing receivables represent those amounts due to the Company as operator of an
oil and gas property by the other working interest owners. Since these owners
could also be the operator of other properties in which the Company is a working
interest owner, the interdependency of the owners tends to assure timely
payment. Balances that are past due for more than 90 days and over $30,000 are
reviewed for collectibility quarterly, and are charged against earnings when the
potential for collection is determined to be remote. The Company recognized such
bad debt expense, included in interest and other income on the Consolidated
Statement of Operations, of $441,000 and $185,000 related to such receivables
for the years ended December 31, 2004 and 2002, respectively. In 2003 the
Company made full or partial collection of several previously written off
balances for a net gain

60

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of approximately $109,000. At December 31, 2004, two outstanding balances
account for approximately 25% and 20% of the total receivable balance,
respectively, and approximately 51% of that outstanding balance is less than 30
days old. No other customers account for more than 10% 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 had recorded a receivable of
approximately $1.5 million from a private oil and gas company representing six
months of override revenue. On November 8, 2004, the Company received $1.5
million as full payment of this receivable. At December 31, 2003, the Company
had 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. In May 2004, the Company received $2.45 million from its insurance
carrier as final settlement for this hurricane damage claim.

CASH HELD FOR REINVESTMENT

The approximately $24.9 million shown as cash held for reinvestment on the
Consolidated Balance Sheet dated December 31, 2003 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. The
Company reinvested the sale proceeds by acquiring the Jalmat field in the
Permian Basin on January 30, 2004.

OTHER ASSETS

The other assets line on the Consolidated Balance Sheet contains items such
as deferred financing costs, refundable deposits and equity investments. As of
December 31, 2004, $7.6 million, or 90% of the $8.4 million balance in other
assets consisted of deferred financing costs. We amortize our deferred financing
costs monthly, over the life of the underlying debt agreement, to interest and
related expenses. For the year ended December 31, 2004 we amortized $1.7 million
of our deferred financing costs.

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.

STATEMENT 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,
2004, 2003 and 2002, was $17.7 million, $26.7 million, and $26.4 million,
respectively. Net cash tax refunds of approximately $0.5 million and $1.8
million were received in the years ended December 31, 2003 and 2002,
respectively. Cash taxes of $481,000 were paid in the year ended December 31,
2004.

The Company issued 16.75 million shares of its common stock in exchange for
$40 million of the 10 7/8% senior subordinated notes due 2007 in three separate
non cash transactions in December 2003, February 2004 and March 2004.

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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. Amounts
contributed by the Company to the Savings Plan for the years ended December 31,
2004, 2003 and 2002 were approximately $345,000, $335,000, and $96,000,
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 was
included in current assets at December 31, 2002 and was approximately $419,000.
An equivalent liability due to the plan participants was 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, 2004, the Company has two active stock-based employee
compensation plans: the 1996 Stock Incentive Plan and the 2004 Stock Incentive
Plan. The 2004 Plan was approved by the Board of Directors on March 4, 2004 and
by the Company's stockholders at the May 19, 2004 annual stockholders' meeting.
One inactive plan, the 1994 Stock Incentive Plan, still has options outstanding
that have not expired or been exercised; however, no new options can be granted
under the plan. 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. Net income would be affected; however, if the exercise price
of the option differed from the market price.

SFAS No. 148, Accounting for Stock-Based Compensation -- Transition and
Disclosure, amends SFAS No. 123 to provide alternative methods of transition for
an entity that voluntarily changes to the fair value based method of accounting
for stock-based employee compensation and to require prominent disclosure about
the effects on reported net income of an entity's accounting policy decisions
with respect to stock-based employee compensation. SFAS No. 148 amends APB
Opinion No. 28, Interim Financial Reporting, to require disclosure about those
effects in interim financial information.

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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 and FASB Statement
No. 148, Accounting for Stock-Based Compensation -- Transition and Disclosure to
stock-based employee compensation (amounts in thousands, except per share
amounts).

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

* The stock-based employee compensation cost, net of the related tax effects,
that would have been included in the determination of net income if the fair
value method had been applied to all awards is $3.9 million, $1.6 million and
$0.8 million for the years ended December 31, 2004, 2003 and 2002,
respectively.

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.

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

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, 2002.................................. $ 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................................ 14,991
Tax effect on hedge activity................................ (748)
--------
Balance at December 31, 2003................................ (5,707)
Net gains (losses) on cash flow hedges...................... (20,656)
Reclassification adjustments................................ 19,597
Tax effect on hedge activity................................ (1,167)
--------
Balance at December 31, 2004................................ $ (7,933)
========

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

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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. The following table shows the changes in the
asset retirement obligation that have occurred since its implementation in 2003
(in thousands):

NEW ACCOUNTING PRONOUNCEMENTS

Staff Accounting Bulletin ("SAB") No. 106, regarding the application of
FASB Statement No. 143, Accounting for Asset Retirement Obligations, by oil and
gas producing companies following the full cost accounting method was issued in
September 2004. SAB 106 provided an interpretation of how a company, after
adopting Statement 143, should compute the full cost ceiling to avoid
double-counting the expected future cash outflows associated with asset
retirement costs. The provisions of this interpretation have been applied by the
Company and has no impact on the financial statements.

SFAS No. 123R, Share-Based Payments was issued in December 2004. SFAS No.
123R requires public companies to measure the cost of employee services in
exchange for an award of equity instruments based on a grant-date fair value of
the award (with limited exceptions), and that cost must generally be recognized
over the vesting period. SFAS No. 123R amends the original SFAS No. 123 and 95
that had allowed companies to choose between expensing stock options or showing
pro forma disclosure only.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SFAS No. 123R becomes effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005. The impact of SFAS No.
123R is dependent upon grants issued and; therefore, cannot be estimated at this
time.

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.

RECLASSIFICATIONS

Certain reclassifications of prior period statements and disclosures 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:

On January 30, 2004, the Company closed the $26.6 million acquisition of
the Jalmat field in the Permian Basin of New Mexico. On April 13, 2004, the
Company acquired an additional 14% working interest in the Jalmat field in Lea
County, New Mexico for $3.6 million cash, before customary adjustments. These
acquisitions added approximately 34.3 BCFE of proved reserves. After completion
of this transaction the Company owns approximately a 94.5% operated working
interest in the Jalmat field.

On December 21, 2004, the Company acquired additional working interests in
the Chocolate Bayou, Southwest Lake Boeuf, Backridge and West Lake Verret fields
for approximately $11.0 million, before customary adjustments. The net reserves
attributable to the interests being acquired are approximately 6 BCFE. The
interests acquired approximately double the Company's current ownership in the
fields and the Company is currently the operator of these fields.

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. The
Company did not make any significant oil and gas property acquisitions during
2002.

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.
In 2002 and 2003, Torch performed services for Mission under various contracts.
All

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

contracts with Torch were terminated effective April 1, 2003. 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.

Mission currently uses an Oracle platform provided by P2 Energy Solutions
under a July 2002 hosting agreement. Torch owns 21.2% 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 $415,000, $667,000 and $373,000 in the years ended
December 31, 2004, 2003 and 2002, respectively.

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 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

Effective November 17, 2004, the Company entered into a Severance Agreement
with Joseph G. Nicknish. Mr. Nicknish previously held the position of Senior
Vice President, Operations and Engineering. Pursuant to an employment agreement
with Mr. Nicknish, upon separation from the Company, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

employment agreement provided for the payment of a severance amount based on
multiples of his current salary at the time of separation. Under the terms of
the Severance Agreement, the Company agreed to pay Mr. Nicknish a severance
amount of $500,000 payable in three equal installments commencing on December
30, 2004 and ending June 30, 2005. Under various programs, Mr. Nicknish had been
granted 574,499 options to acquire the Company's common stock. Upon separation,
these options were deemed exercisable for a period equal to the lesser of (i)
one year following the separation date or (ii) the remaining term of the
applicable option. In addition, the Company agreed to provide Mr. Nicknish with
certain insurance benefits for up to 18 months after the separation date.

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.

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.

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 the
Company's common stock in exchange for the surrender by the Franklin entities of
$10.0 million aggregate principal amount of the Company's 10 7/8% Notes due
2007. Accrued interest on the notes to the date of the agreement was paid on
April 1, 2004, the regularly scheduled interest payment date for the notes, or
upon the occurrence of certain other events

On February 25, 2004, the Company acquired $15 million of its 10 7/8% Notes
due 2007 from Stellar Funding, Ltd. in exchange for 6.25 million shares of the
Company's common stock. On March 15, 2004, the Company acquired an additional
$15 million of its 10 7/8% Notes due 2007 from Harbert Distressed Investment
Master Fund, Ltd. in exchange for 6.0 million shares of the Company's common
stock.

On April 8, 2004, Mission issued 312,000 shares of its common stock in lieu
of cash to its financial advisors as a fee for services rendered during the debt
refinancing discussed below in Note 8. The $1.2 million fair value of this
consideration was recorded as deferred financing costs in the other assets line
of the Consolidated Balance Sheet.

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.

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,

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 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, 2004, 2003 and 2002, the
potentially dilutive options excluded represented 819,498, 1,171,500 and
1,050,500 shares, respectively.

In periods of loss, the effect of potentially dilutive options that are in
the money are excluded from the calculation of diluted earnings per share. For
the year ended December 31, 2002, potential incremental shares of 250,000, 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
and 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK INCENTIVE PLANS

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. 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, 2004, there were 396,500 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.

Detail of stock options outstanding and options exercisable at December 31,
2004 follows:

The estimated weighted average fair value per share of options granted
during 2004, 2003, and 2002 was $7.64, $2.67, and $0.58, 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 year-end for 2002, but quarterly for 2003 and 2004 due to the quarterly
reporting requirements of SFAS No. 148.

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following weighted-average assumptions were used for each calculation

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

(1) There were no grants requiring Black-Scholes calculations in the first and
third quarters of 2004.

A tax benefit related to the exercise of employee stock options of
approximately $1.2 million in 2004 was allocated directly to additional paid in
capital. Such benefit was not material in 2003 and 2002.

Concurrent with the 2001 Bargo 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 of compensation expense
was recognized in the year ended December 31, 2002, 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.

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 had an initial
value of $0.55 for each right granted, had 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. On August 4, 2004, the Compensation Committee of the Board of Directors
of the Company granted to Mr. Cavnar, a nonqualified option to acquire 800,000
shares of the Company's common stock. This option was granted to replace the
grant of 800,000 share appreciation rights made to Mr. Cavnar in November 2003.
The option was granted under the 2004 Incentive Plan, has a term of 10 years, is
fully vested and has a strike price of $0.55 per share, which is the same
exercise price as the surrendered share appreciation rights. As a result of this
option having an exercise price below the market value for the Company's common
stock at the time of issuance, the Company recognized a non-cash compensation
expense of approximately $4.1 million ($2.6 million, net of tax) in the third
quarter of 2004.

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. Hedging
activities decreased revenues by $20.7 million, $15.8 million and $342,000 for
the years 2004, 2003 and 2002, respectively.

The Company's 12-month average realized price, excluding hedges, for
natural gas was $0.12 per MCF less than the NYMEX MMBTU price. The Company's
12-month average realized price, excluding

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hedges, for oil was $1.47 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 gas differential stated above
excludes the impact the Mist field gas production which is sold at an annually
fixed price.

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 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, $418,000 related to the cancelled hedges had not yet been recognized in
earnings. Such amount was amortized from other comprehensive income ("OCI") over
the period of the hedged transactions 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 period
of the hedged transactions. The Company's hedge program resulted in hedge
ineffectiveness recognized in the interest and other income line of the
Consolidated Statement of Operations of a net gain of $108,000 and $985,000 for
the years ended December 31, 2004 and 2003, respectively, and a net loss of $9.1
million for the year ended December 31, 2002.

As the existing hedges, listed in the tables below, 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 a $6.8 million loss.

The following tables detail the cash flow commodity hedges that were in
place at December 31, 2004.

OIL HEDGES

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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 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 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 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, 2004 and 2003 (in
thousands):

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. LONG-TERM DEBT

Long-term debt is comprised of the following at December 31, 2004 and 2003
(in thousands):

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

(1) $34.9 million was available at December, 31, 2004 for additional borrowings
under this facility.

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

2005........................................................ $ --
2006........................................................ --
2007........................................................ 15,000
2008........................................................ 25,000
2009........................................................ --
Thereafter.................................................. 130,000
--------
$170,000
--------

2004 REFINANCING

On April 8, 2004, the Company issued $130 million of 9 7/8 Notes due 2011,
announced the redemption of its 10 7/8% Notes due 2007 and replaced both its
revolving credit facility and its term loan. Those transactions and the details
of the resulting debt are discussed below.

9 7/8% NOTES

On April 8, 2004, the Company issued $130.0 million of its 9 7/8% Notes due
2011 which are guaranteed on an unsubordinated, unsecured basis by all of its
current subsidiaries. Interest on the notes is payable semi-annually, on each
April 1 and October 1, commencing on October 1, 2004.

A portion of the net proceeds from the offering of the 9 7/8% Notes was set
aside to redeem, on May 10, 2004, the $87.4 million aggregate principal amount
of the 10 7/8% Notes that remained outstanding. On April 8, 2004, the remainder
of the net proceeds from the offering of the 9 7/8% Notes, together with $21.5
million that was advanced under the new senior secured revolving credit facility
(as described below) and $25.0 million that was borrowed under the new second
lien term loan (as described below), was used to completely discharge all of the
Company's outstanding indebtedness under its prior revolving credit facility and
term loan.

At any time on or after April 9, 2005 and prior to April 9, 2008, the
Company may redeem up to 35% of the aggregate original principal amount of the
9 7/8% Notes, using the net proceeds of equity offerings, at a redemption price
equal to 109.875% of the principal amount of the 9 7/8% Notes, plus accrued and
unpaid interest. On or after April 9, 2008, the Company may redeem all or a
portion of the

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9 7/8% Notes at the redemption prices (expressed as percentages of principal
amount) set forth below plus accrued and unpaid interest, if redeemed during the
twelve-month period beginning on April 9 of the years indicated below:

If the Company experiences specific kinds of change of control, it may be
required to purchase all or part of the 9 7/8% Notes at a price equal to 101% of
the principal amount together with accrued and unpaid interest.

The 9 7/8% Notes contain covenants that, subject to certain exceptions and
qualifications, limit the Company's ability and the ability of certain of its
subsidiaries to:

- incur additional indebtedness or issue certain types of preferred stock
or redeemable stock;

- transfer or sell assets;

- enter into sale and leaseback transactions;

- pay dividends or make other distributions on stock, redeem stock or
redeem subordinated debt;

- enter into transactions with affiliates;

- create liens on its assets;

- guarantee other indebtedness;

- enter into agreements that restrict dividends from subsidiaries;

- make investments;

- sell capital stock of subsidiaries; and

- merge or consolidate.

Standard and Poor's and Moody's currently publish debt ratings for the
9 7/8% Notes. Their ratings consider a number of items including the Company's
debt levels, planned asset sales, near-term and long-term production growth
opportunities, capital allocation challenges and commodity price levels.
Standard & Poor's rating on the 9 7/8% Notes is "CCC" and Moody's rating is
"Caa2." A decline in credit ratings will not create a default or other
unfavorable change in the 9 7/8% Notes.

SENIOR SECURED REVOLVING CREDIT FACILITY

On April 8, 2004, the Company entered into a senior secured revolving
credit facility led by Wells Fargo Bank, N.A. The facility, which matures on
April 8, 2007, is secured by a first priority mortgage and security interest in
at least 85% of the Company's oil and gas properties, all of the ownership
interests of all of the Company's subsidiaries, and the Company's equipment,
accounts receivable, inventory, contract rights, general intangibles and other
assets. The facility is also guaranteed by all of the Company's subsidiaries.

Availability under the facility, which includes a $3 million subfacility
for standby letters of credit, is subject to a borrowing base that is determined
at the sole discretion of the facility lenders. The initial borrowing base of
the facility was $50 million, of which $30 million was available for general
corporate purposes and $20 million was available for the acquisition of oil and
gas properties approved by the

75

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

lenders. The borrowing base is redetermined on each April 1 and October 1.
Mission and the lenders each have the option to request one unscheduled interim
redetermination between scheduled redetermination dates. On October 1, 2004, it
was determined that there would be no change in the borrowing base.

On April 8, 2004, the Company was advanced $21.5 million under the
facility, which amount, together with a portion of the net proceeds from the
offering of the 9 7/8% Notes and $25 million that was borrowed under the new
second lien term loan (as described below), was used to completely discharge all
of the Company's outstanding indebtedness under its prior revolving credit
facility and term loan. At December 31, 2004, $15.0 million in borrowings were
outstanding and $34.9 million was available for borrowing ($20 million of which
is restricted to the acquisition of oil and gas properties approved by the
lenders).

Advances under the facility bear interest, at the Company's option, at
either (i) a margin (which varies from 25.0 basis points to 125.0 basis points
based upon utilization of the borrowing base) over the base rate, which is the
higher of (a) Wells Fargo's prime rate in effect on that day, and (b) the
federal funds rate in effect on that day as announced by the Federal Reserve
Bank of New York, plus 0.5%; or (ii) a margin (which varies from 175.0 basis
points to 275.0 basis points based upon utilization of the borrowing base) over
LIBOR. The Company is allowed to prepay any base rate or LIBOR loan without
penalty, provided that each prepayment is at least $500,000 and multiples of
$100,000 in excess thereof, plus accrued and unpaid interest.

Standby letters of credit may be issued under the $3 million letter of
credit subfacility. Mission is required to pay, to the issuer of the letter of
credit, with respect to each issued letter of credit, (i) a per annum letter of
credit fee equal to the LIBOR margin then in effect multiplied by the face
amount of such letter of credit plus (ii) an issuing fee of the greater of $500
or 12.5 basis points.

The facility requires the Company to hedge forward, on a rolling 12-month
basis, at least 50% of proved producing volumes projected to be produced over
the following 12 months. The Company is also required to hedge forward, on a
rolling 12-month basis, at least 25% of proved producing volumes projected to be
produced over the succeeding 12-month period. Any time that Mission has
borrowings under the facility in excess of 70% of the borrowing base available
for general corporate purposes, the agent under the facility may require Mission
to hedge a percentage of projected production volumes on terms acceptable to the
agent.

The facility also contains the following restrictions on hedging
arrangements and interest rate agreements: (i) the hedge provider must be a
lender under the facility or an unsecured counterparty acceptable to the agent
under the facility; and (ii) total notional volume must be not more than 75% of
scheduled proved producing net production quantities in any period or, with
respect to interest rate agreements, notional principal amount must not exceed
75% of outstanding loans, including future reductions in the borrowing base.

The facility contains the following covenants which are considered
important to Mission's operations. At December 31, 2004, the Company was in
compliance with each of the following covenants:

- Maintain a current ratio of consolidated current assets (as defined in
the facility) to consolidated current liabilities (as defined in the
facility) of not less than 1.0 to 1.0;

- Maintain (on an annualized basis until the passing of four fiscal
quarters and thereafter on a rolling four quarter basis) an interest
coverage ratio (as defined in the facility) of no less than (i) 2.50 for
June 30, 2004 through December 31, 2004, (ii) 2.75 for March 31, 2005
through June 30, 2005, and (iii) 3.0 for September 30, 2005 and
thereafter;

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- Maintain (on an annualized basis until the passing of four fiscal
quarters and thereafter on a rolling four quarter basis) a leverage ratio
(as defined in the facility) of no more than (i) 3.75 for June 30, 2004
through September 30, 2004, and (ii) 3.5 for December 31, 2004 and
thereafter; and

- Maintain a tangible net worth (as defined in the facility) of not less
than 85% of tangible net worth at March 31, 2004, plus 50% of positive
net income after tax distributions, plus 100% of equity offerings after
March 31, 2004, excluding any asset impairment charges.

The facility also includes restrictions with respect to changes in the
nature of the Company's business; sale of all or a substantial or material part
of its assets; mergers, acquisitions, reorganizations and recapitalizations;
liens; guarantees; debt; leases; dividends and other distributions; investments;
debt prepayments; sale-leasebacks; capital expenditures; lease expenditures; and
transactions with affiliates.

SECOND LIEN TERM LOAN

On April 8, 2004, Mission entered into a second lien term loan with a
syndicate of lenders arranged by Guggenheim Corporate Funding, LLC. The loan,
which matures on April 8, 2008, is secured by a second priority security
interest in the assets securing the senior secured revolving credit facility.
The facility is also guaranteed by all of Mission's subsidiaries. On April 8,
2004, the Company borrowed the $25.0 million under the loan, which amount,
together with a portion of the net proceeds from the offering of the 9 7/8%
Notes and $21.5 million borrowed under the senior secured revolving credit
facility (as described above), was used to completely discharge all of the
outstanding indebtedness under the prior revolving credit facility and term
loan.

The loan accrues interest in each monthly interest period at the rate of
30-day LIBOR plus 525 basis points per annum, payable monthly in cash. The
Company may prepay the loan at any time after the date six months and one day
after April 8, 2004 in whole or in part in multiples of $1 million at the prices
(expressed as percentages of principal amount) set forth below, plus accrued and
unpaid interest, if prepaid during each successive 12-month period beginning on
April 9th of each year indicated below:

Provided, however, that no prepayment shall be made prior to the date six months
and one day after April 8, 2004.

The loan contains covenants that are no more restrictive than those
contained in the senior secured revolving credit facility.

REDEEMED 10 7/8% NOTES

In April 1997, the Company issued $100 million of 10 7/8% Notes due 2007.
On May 29, 2001, the Company issued an additional $125 million of 10 7/8% Notes
with identical terms to the notes issued in April 1997 at a premium of $1.9
million. The premium, shown separately on the Consolidated Balance Sheet, was
amortized as a reduction of interest expense over the life of the 10 7/8% Notes
so that the effective interest rate on the additional 10 7/8% Notes was 10.5%.
Interest on the 10 7/8% Notes was payable semi-annually on April 1 and October
1.

On March 28, 2003, the Company acquired, in a private transaction with
various funds affiliated with Farallon Capital Management, LLC, approximately
$97.6 million in principal amount of the 10 7/8% Notes for approximately $71.7
million, plus accrued interest. Including costs of the transaction and the
removal

77

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of $2.2 million of previously deferred financing costs related to the acquired
10 7/8% Notes, the Company recognized a $22.4 million gain on the extinguishment
of the 10 7/8% Notes.

In December 2003, February 2004 and March 2004, the Company, in three
private transactions, acquired $40.0 million aggregate principal amount of the
10 7/8% Notes in exchange for an aggregate of 16.75 million shares of its common
stock as summarized below:

78

MISSION RESOURCES CORPORATION

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, 2004 and
2003 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 a portion of its deferred tax
asset related to state tax net operating loss carryforwards. 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 $3.9
million and $5.1 million for the years ending December 31, 2004 and 2003,
respectively.

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

A tax benefit related to the exercise of employee stock options of
approximately $1,206,000 was allocated directly to additional paid-in capital in
2004. Such benefit was not material in 2003 and 2002.

79

MISSION RESOURCES CORPORATION

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% 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,
2004, management believes that the limitations imposed by Section 382 will not
result in the Company being unable to fully utilize its net operating loss and
tax credit carryforwards to offset future taxable income and related tax
liabilities.

At December 31, 2004, the Company had federal regular tax net operating
loss carryforwards of approximately $92.6 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, Eunice, New
Mexico and Lafayette, Louisiana. At December 31, 2004, the minimum future
payments under the terms of the Company's office space operating leases are as
follows:

80

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Rent expense was approximately $721,000, $700,000, and $685,000 in 2004,
2003 and 2002, 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. As of December 31, 2004, the Company has accrued a liability for
approximately $137,000 for the abandonment and cleanup of the Bayou Ferblanc
field and a $370,000 liability for its proposal to settle on abandonment issues
at the West Lake Ponchartrain field.

11. RESTRUCTURING

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

In 1993 and 1996 the Company entered into agreements with surety companies
and with Torch Energy Advisors Incorporated ("Torch") and Nuevo Energy Company
("Nuevo") whereby the surety

81

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. Torch currently has no bonds outstanding pursuant
to these agreements and Nuevo has issued approximately $34.3 million of bonds.
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. Effective May 17, 2004, Plains Exploration and Production Company
acquired Nuevo Energy Company.

The Company's subsidiaries, Mission E&P Limited Partnership, Mission
Holdings LLC and Black Hawk Oil Company are guarantors under the Senior Secured
Revolving Credit Facility, the Second Lien Term Loan and the indenture for the
9 7/8 Notes.

13. SUPPLEMENTAL GUARANTOR INFORMATION -- UNAUDITED

Mission E&P Limited Partnership, Mission Holdings LLC and Black Hawk Oil
Company, all subsidiaries of Mission Resources Corporation (collectively, the
"Guarantor Subsidiaries") are guarantors under the senior secured revolving
credit facility, the second lien term loan and the indenture for the 9 7/8%
Notes. The Company does not believe that separate financial statements and other
disclosures concerning the Guarantor Subsidiaries would provide any additional
information that would be material to investors in making an investment
decision.

CONDENSED CONSOLIDATING BALANCE SHEETS -- UNAUDITED
AS OF DECEMBER 31, 2004

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING INCOME STATEMENTS -- UNAUDITED
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS -- UNAUDITED
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004

83

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEETS -- UNAUDITED
AS OF DECEMBER 31, 2003

CONDENSED CONSOLIDATING INCOME STATEMENTS -- UNAUDITED
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2003

84

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS -- UNAUDITED
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2003

CONDENSED CONSOLIDATING INCOME STATEMENTS -- UNAUDITED
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2002

85

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS -- UNAUDITED
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2002

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

86

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The loss in the second quarter of 2004 was attributable to a $2.6 million
expense ($1.7 million, net of taxes) from the extinguishment of debt.

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.

15. 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 report for the years ended December 31, 2004,
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;

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.

87

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

COSTS INCURRED (IN THOUSANDS):

CAPITALIZED COSTS (IN THOUSANDS):

RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (IN THOUSANDS):

88

MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

PROVED AND PROVED DEVELOPED RESERVES

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

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MISSION RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DISCOUNTED FUTURE NET CASH FLOWS

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

90

MISSION RESOURCES CORPORATION

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):

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 $43.33, $32.47
and $31.17 per barrel and $6.18, $5.97 and $4.74 per MMBTU, for December 31,
2004, 2003 and 2002, 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 flow would have decreased
discounted future net cash flows by approximately $6.9 million, $6.4 million and
$7.7 million as of December 31, 2004, 2003 and 2002, respectively.

91

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.

MANAGEMENT, REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management's Report on Internal Controls over Financial Reporting which
appears on page 54, is incorporated herein by reference.

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.

ITEM 9B. OTHER INFORMATION

None.

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, 2004. 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, 2004. Such information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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, 2004. Such information is incorporated herein by reference.

92

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, 2004. Such information is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING 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, 2004. Such information is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

3. Exhibits.

2.1 Agreement and Plan of Merger dated January 24, 2001 between
the Company and Bargo Energy Company (incorporated by
reference to Exhibit 2.1 to the Company's 8-K filed on
January 26, 2001).

3.1 Certificate of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement No. 33-76570 filed on March 17, 1994).

3.2 Certificate of Amendment to Certificate of Incorporation
(incorporated by reference to Exhibit 3.2 to the Company's
Annual Report on Form 10-K filed on September 27, 1997).

3.3 Certificate of Designation, Preferences and Rights of the
Series A Preferred Stock of the Company (incorporated by
reference to Exhibit 3.3 to the Company's Annual Report on
Form 10-K filed on September 27, 1997).

3.4 Certificate of Merger of Bargo Energy Company into the
Company (incorporated by reference to Exhibit 3.4 to the
Company's Annual Report on Form 10-K filed on March 31,
2003).

3.5 Certificate of Amendment to Certificate of Incorporation of
the Company (incorporated by reference to Exhibit 3.5 to the
Company's Annual Report on Form 10-K filed on March 31,
2003).

3.6 By-laws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement No. 33-76570
filed on March 17, 1994).

3.7 Amendment to the Company's Bylaws adopted on November 21,
1997 (incorporated by reference to Exhibit 3.5 to the
Company's Annual Report on Form 10-K filed on March 27,
1998).

3.8 Amendment to the Company's Bylaws adopted on March 27, 1998
(incorporated by reference to Exhibit 3.6 to the Company's
Annual Report on Form 10-K filed on March 27, 1998).

4.1 Specimen Stock Certificate (incorporated by reference to
Exhibit 4.1 to the Company's Annual Report on Form 10-K
filed on March 31, 2003).

4.2 Rights Agreement between the Company and American Stock
Transfer & Trust Company (incorporated herein by reference
to Exhibit 1 to the Company's Registration Statement on Form
8-A filed on September 19, 1997).

4.3 Amendment to Rights Agreement dated as of December 17, 2003,
by and between Mission Resources Corporation and American
Stock Transfer & Trust Company (incorporated by reference to
Exhibit 4.1 to the Company's Current Report on Form 8-K
filed on December 18, 2003).

4.4 Amendment to Rights Agreement dated as of February 25, 2004,
by and between the Company and American Stock Transfer &
Trust Company (incorporated by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on February
26, 2004).

93

4.5 Amendment to Rights Agreement dated as of March 15, 2004 by
and between the Company and American Stock Transfer & Trust
Company (incorporated by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on March 16,
2004).

4.6 Indenture dated as of May 29, 2001 among the Company, the
Subsidiary Guarantors named therein and the Bank of New
York, as Trustee (incorporated by reference to Exhibit 4.1
of the Company's Registration Statement on Form S-4 filed on
July 27, 2001).

4.7 Registration Rights Agreement dated December 17, 2003, by
and among the Company and FTVIPT -- Franklin Income
Securities Fund and Franklin Custodian Funds -- Income
Series (incorporated by reference to Exhibit 99.3 to the
Company's Current Report on Form 8-K filed on December 18,
2003).

4.8 Registration Rights Agreement dated February 25, 2004, by
and among the Company and Stellar Funding Ltd. (incorporated
by reference to Exhibit 99.3 to the Company's Current Report
on Form 8-K filed on February 26, 2004).

4.9 Registration Rights Agreement dated March 15, 2004, by and
between the Company and Harbert Distressed Investment Master
Fund, Ltd. (incorporated by reference to Exhibit 99.3 to the
Company's Current Report on Form 8-K filed on March 16,
2004).

4.10 Indenture dated as of April 8, 2004, among the Company, the
Guarantors named therein and The Bank of New York, as
Trustee, relating to the Company's 9 7/8% Senior Notes due
2011 (incorporated by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K/A filed on April 15,
2004).

10.1+ 1994 Stock Incentive Plan (incorporated by reference to
Exhibit 10.9 to the Company's Registration Statement No.
33-76570 filed on March 17, 1994).

10.2+ 1996 Stock Incentive Plan (incorporated by reference to
Exhibit A to the Company's Proxy Statement on Schedule 14A
filed on October 21, 1996).

10.3+ 2004 Incentive Plan (incorporated by reference to Appendix C
to the Company's Proxy Statement on Schedule 14A filed on
March 30, 2004).

10.4 Amended and Restated Credit Agreement, dated as of March 28,
2003, among the Company, Farallon Energy Funding, LLC, as
Arranger and Lender, Jefferies & Company, Inc., as
Syndication Agent and Foothill Capital Corporation, as
Administrative Agent (incorporated by reference to Exhibit
99.2 to the Company's Current Report on Form 8-K, filed
April 1, 2003).

10.5 Second Amended, Restated and Consolidated Guaranty and
Collateral Agreement, dated as of march 28, 2003, made by
the Company and certain of its Subsidiaries, in favor of
Foothill Capital Corporation, as Administrative Agent
(incorporated by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K, filed April 1, 2003).

10.6 Second Amended and Restated Credit Agreement among the
Company, as Borrower, the Several Lenders from Time to Time
Parties Hereto, Farallon Energy Lending, L.L.C., as Arranger
Jefferies & Company, Inc., as Syndication Agent and Wells
Fargo Foothill, Inc., as Administrative Agent dated as of
June 5, 2003 (incorporated by reference to Exhibit 99.2 to
the Current Report on Form 8-K filed on June 17, 2003).

10.7 Third Amended, Restated And Consolidated Guaranty And
Collateral Agreement, dated as of June 5, 2003, made by the
Company and certain of its Subsidiaries, in favor of Wells
Fargo Foothill, Inc., as Administrative Agent (incorporated
by reference to Exhibit 99.3 to the Current Report on Form
8-K filed on June 17, 2003).

10.8 First Amendment to and Waiver of Second Amended and Restated
Credit Agreement, dated as of June 25, 2003, among the
Company, the several banks and other financial institutions
or entities from time to time parties to the Amendment,
Farallon Energy Lending, L.L.C., as sole advisor, sole lead
arranger and sole bookrunner, and Wells Fargo Foothill, Inc,
as administrative agent (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q,
filed November 13, 2003).

94

10.9 Second Amendment, dated October 22, 2003, to the Second
Amended and Restated Credit Agreement, dated as of June 5,
2003, by and among the Company, the several banks and other
financial institutions or entities from time to time parties
thereto, Farallon Energy Lending, L.L.C., as sole advisor,
sole lead arranger and sole bookrunner, Jefferies & Company,
Inc., as the syndication agent, and Wells Fargo Foothill,
Inc, formerly known as Foothill Capital Corporation, as
administrative agent (incorporated by reference to Exhibit
10.4 to the Company's Quarterly Report on Form 10-Q, filed
November 13, 2003).

10.10 Credit Agreement dated as of April 8, 2004, among the
Company, as Borrower, Wells Fargo Bank, National
Association, as Lead Arranger and Administrative Agent, and
the Lenders signatory thereto (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K/ A
filed on April 15, 2004).

10.11 Term Loan Agreement dated as of April 8, 2004, among the
Company, as Borrower, Guggenheim Corporate Funding, LLC, as
Collateral Agent, and the Lenders signatory thereto
(incorporated by reference to Exhibit 10.2 to the Company's
Current Report on Form 8-K/A filed on April 15, 2004).

10.12 Intercreditor Agreement dated as of April 8, 2004, by and
between the Company, the Company's Subsidiaries, Wells Fargo
Bank, National Association and Guggenheim Corporate Funding
LLC (incorporated by reference to Exhibit 10.3 to the
Company's Current Report on Form 8-K/A filed on April 15,
2004).

10.13 Purchase and Sale Agreement, dated as of March 28, 2003, by
and between Farallon Capital Management, LLC and the
Company, as Administrative Agent (incorporated by reference
to Exhibit 99.3 to the Company's Current Report on Form 8-K,
filed April 1, 2003).

10.14 Purchase and Sale Agreement, dated as of December 17, 2003,
by and among the Company and FTVIPT -- Franklin Income
Securities Fund and Franklin Custodian Funds -- Income
Series (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K filed on December 18,
2003).

10.15 Purchase and Sale Agreement, dated as of February 25, 2004,
by and between the Company and Stellar Funding Ltd.
(incorporated by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K filed on February 26, 2004).

10.16 Purchase and Sale Agreement, dated as of March 15, 2004, by
and between the Company and Harbert Distressed Investment
Master Fund, Ltd. (incorporated by reference to Exhibit 99.2
to the Company's Current Report on Form 8-K filed on March
16, 2004).

10.17+ Employment Agreement dated August 8, 2002, between the
Company and Robert L. Cavnar (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q
filed November 14, 2002).

10.18+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and Robert L. Cavnar (incorporated
by reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q filed November 10, 2004).

10.19+ Employment Agreement dated October 8, 2002, between the
Company and Richard W. Piacenti (incorporated by reference
to Exhibit 10.4 to the Company's Quarterly Report on Form
10-Q filed November 14, 2002).

10.20+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and Richard W. Piacenti
(incorporated by reference to Exhibit 10.5 to the Company's
Quarterly Report on Form 10-Q filed November 10, 2004).

10.21+ Employment Agreement dated November 7, 2002, between the
Company and John L. Eells (incorporated by reference to
Exhibit 10.14 to the Company's Annual Report on Form 10-K
filed on March 31, 2003).

10.22+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and John L. Eells (incorporated by
reference to Exhibit 10.6 to the Company's Quarterly Report
on Form 10-Q filed November 10, 2004).

10.23+ Employment Agreement dated November 6, 2002, between the
Company and Joseph G. Nicknish (incorporated by reference to
Exhibit 10.15 to the Company's Annual Report on Form 10-K
filed on March 31, 2003).

95

10.24+ First Amendment to Employment Agreement dated November 9, 2004
between the Company and Joseph G. Nicknish (incorporated by
reference to Exhibit 10.7 to the Company's Quarterly Report on
Form 10-Q filed November 10, 2004).

10.25+ Severance Agreement dated November 17, 2004, between the Company
and Joseph G. Nicknish (incorporated by reference to Exhibit 10.1
to the Company's Current Report on Form 8-K filed on November 23,
2004).

10.26+ Employment Agreement effective November 4, 2003 between the
Company and Marshall L. Munsell (incorporated by reference to
Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed
on November 13, 2003).

10.27+ First Amendment to Employment Agreement dated November 9, 2004
between the Company and Marshall L. Munsell (incorporated by
reference to Exhibit 10.8 to the Company's Quarterly Report on
Form 10-Q filed November 10, 2004).

10.28*+ Employment Agreement dated as of November 1, 2004, between the
Company and Thomas C. Langford.

10.29+ Non-statutory Stock Option Agreement dated as of November 1,
2004, between the Company and Thomas C. Langford (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form
8-K filed on November 2, 2004).

10.30+ Form of Indemnification Agreement between the Company and each of
its directors and executive officers (incorporated by reference
to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q
filed November 14, 2002).

10.31+ Form of Nonstatutory Stock Option Grant Agreement under the
Company's 2004 Incentive Plan (incorporated by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed
November 10, 2004).

10.32+ Form of Director Non-Qualified Stock Option (incorporated by
reference to Exhibit 10.2 to the Company's Quarterly Report on
Form 10-Q filed November 10, 2004).

10.33+ Form of Incentive Stock Option Grant Agreement under the
Company's 2004 Incentive Plan (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed
November 10, 2004).

10.34*+ First Amendment to the Employment Agreement dated as of November
1, 2004, between the Company and Thomas C. Langford.

21.1* Subsidiaries of the Company.

23.1* Consent of KPMG LLP.

23.2* Consent of Netherland Sewell & Associates, Inc.

31.1* Certification of Chief Executive Officer pursuant to Rule
13a-14(a)/Rule 15d-14(a), promulgated under the Securities
Exchange Act of 1934, as amended.

31.2* Certification of Chief Financial Officer pursuant to Rule
13a-14(a)/Rule 15d-14(a), promulgated under the Securities
Exchange Act of 1934, as amended.

32.1* Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of
Chief Executive Officer of the Company.

32.2* Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of
Chief Financial Officer of the Company.

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

* Filed herewith.

+ Management contract or compensatory plan or arrangement

(b) Exhibits.

See item 15(a)(3) above.

(c) Financial Statement Schedules

None.

96

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.

- MBOE -- One thousand BOE.

- MMBOE -- One million BOE.

- MMBBL -- One million BBLs.

- NGLs -- Natural gas liquids.

- TCF -- One trillion cubic feet of natural gas.

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

97

taxes to provide what we believe is a better basis for comparison of our
reserves to other producers who may have different tax rates.

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, 2004, 2003 or 2002 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
98

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 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.

99

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 8, 2005

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.

100

EXHIBIT INDEX

2.1 Agreement and Plan of Merger dated January 24, 2001 between
the Company and Bargo Energy Company (incorporated by
reference to Exhibit 2.1 to the Company's 8-K filed on
January 26, 2001).

3.1 Certificate of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement No. 33-76570 filed on March 17, 1994).

3.2 Certificate of Amendment to Certificate of Incorporation
(incorporated by reference to Exhibit 3.2 to the Company's
Annual Report on Form 10-K filed on September 27, 1997).

3.3 Certificate of Designation, Preferences and Rights of the
Series A Preferred Stock of the Company (incorporated by
reference to Exhibit 3.3 to the Company's Annual Report on
Form 10-K filed on September 27, 1997).

3.4 Certificate of Merger of Bargo Energy Company into the
Company (incorporated by reference to Exhibit 3.4 to the
Company's Annual Report on Form 10-K filed on March 31,
2003).

3.5 Certificate of Amendment to Certificate of Incorporation of
the Company (incorporated by reference to Exhibit 3.5 to the
Company's Annual Report on Form 10-K filed on March 31,
2003).

3.6 By-laws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement No. 33-76570
filed on March 17, 1994).

3.7 Amendment to the Company's Bylaws adopted on November 21,
1997 (incorporated by reference to Exhibit 3.5 to the
Company's Annual Report on Form 10-K filed on March 27,
1998).

3.8 Amendment to the Company's Bylaws adopted on March 27, 1998
(incorporated by reference to Exhibit 3.6 to the Company's
Annual Report on Form 10-K filed on March 27, 1998).

4.1 Specimen Stock Certificate (incorporated by reference to
Exhibit 4.1 to the Company's Annual Report on Form 10-K
filed on March 31, 2003).

4.2 Rights Agreement between the Company and American Stock
Transfer & Trust Company (incorporated herein by reference
to Exhibit 1 to the Company's Registration Statement on Form
8-A filed on September 19, 1997).

4.3 Amendment to Rights Agreement dated as of December 17, 2003,
by and between Mission Resources Corporation and American
Stock Transfer & Trust Company (incorporated by reference to
Exhibit 4.1 to the Company's Current Report on Form 8-K
filed on December 18, 2003).

4.4 Amendment to Rights Agreement dated as of February 25, 2004,
by and between the Company and American Stock Transfer &
Trust Company (incorporated by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on February
26, 2004).

4.5 Amendment to Rights Agreement dated as of March 15, 2004 by
and between the Company and American Stock Transfer & Trust
Company (incorporated by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on March 16,
2004).

4.6 Indenture dated as of May 29, 2001 among the Company, the
Subsidiary Guarantors named therein and the Bank of New
York, as Trustee (incorporated by reference to Exhibit 4.1
of the Company's Registration Statement on Form S-4 filed on
July 27, 2001).

4.7 Registration Rights Agreement dated December 17, 2003, by
and among the Company and FTVIPT -- Franklin Income
Securities Fund and Franklin Custodian Funds -- Income
Series (incorporated by reference to Exhibit 99.3 to the
Company's Current Report on Form 8-K filed on December 18,
2003).

4.8 Registration Rights Agreement dated February 25, 2004, by
and among the Company and Stellar Funding Ltd. (incorporated
by reference to Exhibit 99.3 to the Company's Current Report
on Form 8-K filed on February 26, 2004).

4.9 Registration Rights Agreement dated March 15, 2004, by and
between the Company and Harbert Distressed Investment Master
Fund, Ltd. (incorporated by reference to Exhibit 99.3 to the
Company's Current Report on Form 8-K filed on March 16,
2004).

4.10 Indenture dated as of April 8, 2004, among the Company, the
Guarantors named therein and The Bank of New York, as
Trustee, relating to the Company's 9 7/8% Senior Notes due
2011 (incorporated by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K/A filed on April 15,
2004).

10.1+ 1994 Stock Incentive Plan (incorporated by reference to
Exhibit 10.9 to the Company's Registration Statement No.
33-76570 filed on March 17, 1994).

10.2+ 1996 Stock Incentive Plan (incorporated by reference to
Exhibit A to the Company's Proxy Statement on Schedule 14A
filed on October 21, 1996).

10.3+ 2004 Incentive Plan (incorporated by reference to Appendix C
to the Company's Proxy Statement on Schedule 14A filed on
March 30, 2004).

10.4 Amended and Restated Credit Agreement, dated as of March 28,
2003, among the Company, Farallon Energy Funding, LLC, as
Arranger and Lender, Jefferies & Company, Inc., as Syndica-
tion Agent and Foothill Capital Corporation, as
Administrative Agent (incorporated by reference to Exhibit
99.2 to the Company's Current Report on Form 8-K, filed
April 1, 2003).

10.5 Second Amended, Restated and Consolidated Guaranty and
Collateral Agreement, dated as of march 28, 2003, made by
the Company and certain of its Subsidiaries, in favor of
Foothill Capital Corporation, as Administrative Agent
(incorporated by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K, filed April 1, 2003).

10.6 Second Amended and Restated Credit Agreement among the
Company, as Borrower, the Several Lenders from Time to Time
Parties Hereto, Farallon Energy Lending, L.L.C., as Arranger
Jefferies & Company, Inc., as Syndication Agent and Wells
Fargo Foothill, Inc., as Administrative Agent dated as of
June 5, 2003 (incorporated by reference to Exhibit 99.2 to
the Current Report on Form 8-K filed on June 17, 2003).

10.7 Third Amended, Restated And Consolidated Guaranty And
Collateral Agreement, dated as of June 5, 2003, made by the
Company and certain of its Subsidiaries, in favor of Wells
Fargo Foothill, Inc., as Administrative Agent (incorporated
by reference to Exhibit 99.3 to the Current Report on Form
8-K filed on June 17, 2003).

10.8 First Amendment to and Waiver of Second Amended and Restated
Credit Agreement, dated as of June 25, 2003, among the
Company, the several banks and other financial institutions
or entities from time to time parties to the Amendment,
Farallon Energy Lending, L.L.C., as sole advisor, sole lead
arranger and sole bookrunner, and Wells Fargo Foothill, Inc,
as administrative agent (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q,
filed November 13, 2003).

10.9 Second Amendment, dated October 22, 2003, to the Second
Amended and Restated Credit Agreement, dated as of June 5,
2003, by and among the Company, the several banks and other
financial institutions or entities from time to time parties
thereto, Farallon Energy Lending, L.L.C., as sole advisor,
sole lead arranger and sole bookrunner, Jefferies & Company,
Inc., as the syndication agent, and Wells Fargo Foothill,
Inc, formerly known as Foothill Capital Corporation, as
administrative agent (incorporated by reference to Exhibit
10.4 to the Company's Quarterly Report on Form 10-Q, filed
November 13, 2003).

10.10 Credit Agreement dated as of April 8, 2004, among the
Company, as Borrower, Wells Fargo Bank, National
Association, as Lead Arranger and Administrative Agent, and
the Lenders signatory thereto (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K/ A
filed on April 15, 2004).

10.11 Term Loan Agreement dated as of April 8, 2004, among the
Company, as Borrower, Guggenheim Corporate Funding, LLC, as
Collateral Agent, and the Lenders signatory thereto
(incorporated by reference to Exhibit 10.2 to the Company's
Current Report on Form 8-K/A filed on April 15, 2004).

10.12 Intercreditor Agreement dated as of April 8, 2004, by and
between the Company, the Company's Subsidiaries, Wells Fargo
Bank, National Association and Guggenheim Corporate Funding
LLC (incorporated by reference to Exhibit 10.3 to the
Company's Current Report on Form 8-K/A filed on April 15,
2004).

10.13 Purchase and Sale Agreement, dated as of March 28, 2003, by
and between Farallon Capital Management, LLC and the
Company, as Administrative Agent (incorporated by reference
to Exhibit 99.3 to the Company's Current Report on Form 8-K,
filed April 1, 2003).

10.14 Purchase and Sale Agreement, dated as of December 17, 2003,
by and among the Company and FTVIPT -- Franklin Income
Securities Fund and Franklin Custodian Funds -- Income
Series (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K filed on December 18,
2003).

10.15 Purchase and Sale Agreement, dated as of February 25, 2004,
by and between the Company and Stellar Funding Ltd.
(incorporated by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K filed on February 26, 2004).

10.16 Purchase and Sale Agreement, dated as of March 15, 2004, by
and between the Company and Harbert Distressed Investment
Master Fund, Ltd. (incorporated by reference to Exhibit 99.2
to the Company's Current Report on Form 8-K filed on March
16, 2004).

10.17+ Employment Agreement dated August 8, 2002, between the
Company and Robert L. Cavnar (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q
filed November 14, 2002).

10.18+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and Robert L. Cavnar (incorporated
by reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q filed November 10, 2004).

10.19+ Employment Agreement dated October 8, 2002, between the
Company and Richard W. Piacenti (incorporated by reference
to Exhibit 10.4 to the Company's Quarterly Report on Form
10-Q filed November 14, 2002).

10.20+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and Richard W. Piacenti
(incorporated by reference to Exhibit 10.5 to the Company's
Quarterly Report on Form 10-Q filed November 10, 2004).

10.21+ Employment Agreement dated November 7, 2002, between the
Company and John L. Eells (incorporated by reference to
Exhibit 10.14 to the Company's Annual Report on Form 10-K
filed on March 31, 2003).

10.22+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and John L. Eells (incorporated by
reference to Exhibit 10.6 to the Company's Quarterly Report
on Form 10-Q filed November 10, 2004).

10.23+ Employment Agreement dated November 6, 2002, between the
Company and Joseph G. Nicknish (incorporated by reference to
Exhibit 10.15 to the Company's Annual Report on Form 10-K
filed on March 31, 2003).

10.24+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and Joseph G. Nicknish
(incorporated by reference to Exhibit 10.7 to the Company's
Quarterly Report on Form 10-Q filed November 10, 2004).

10.25+ Severance Agreement dated November 17, 2004, between the
Company and Joseph G. Nicknish (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K
filed on November 23, 2004).

10.26+ Employment Agreement effective November 4, 2003 between the
Company and Marshall L. Munsell (incorporated by reference
to Exhibit 10.5 to the Company's Quarterly Report on Form
10-Q filed on November 13, 2003).

10.27+ First Amendment to Employment Agreement dated November 9,
2004 between the Company and Marshall L. Munsell
(incorporated by reference to Exhibit 10.8 to the Company's
Quarterly Report on Form 10-Q filed November 10, 2004).

10.28*+ Employment Agreement dated as of November 1, 2004, between
the Company and Thomas C. Langford.

10.29+ Non-statutory Stock Option Agreement dated as of November 1,
2004, between the Company and Thomas C. Langford
(incorporated by reference to Exhibit 10.1 to the Company's
Current Report on Form 8-K filed on November 2, 2004).

10.30+ Form of Indemnification Agreement between the Company and
each of its directors and executive officers (incorporated
by reference to Exhibit 10.5 to the Company's Quarterly
Report on Form 10-Q filed November 14, 2002).

10.31+ Form of Nonstatutory Stock Option Grant Agreement under the
Company's 2004 Incentive Plan (incorporated by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q
filed November 10, 2004).

10.32+ Form of Director Non-Qualified Stock Option (incorporated by
reference to Exhibit 10.2 to the Company's Quarterly Report
on Form 10-Q filed November 10, 2004).

10.33+ Form of Incentive Stock Option Grant Agreement under the
Company's 2004 Incentive Plan (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q
filed November 10, 2004).

10.34*+ First Amendment to the Employment Agreement dated as of
November 1, 2004, between the Company and Thomas C.
Langford.

21.1* Subsidiaries of the Company.

23.1* Consent of KPMG LLP.

23.2* Consent of Netherland Sewell & Associates, Inc.

31.1* Certification of Chief Executive Officer pursuant to Rule
13a-14(a)/Rule 15d-14(a), promulgated under the Securities
Exchange Act of 1934, as amended.

31.2* Certification of Chief Financial Officer pursuant to Rule
13a-14(a)/Rule 15d-14(a), promulgated under the Securities
Exchange Act of 1934, as amended.

32.1* Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,
of Chief Executive Officer of the Company.

32.2* Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,
of Chief Financial Officer of the Company.

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

* Filed herewith.

+ Management contract or compensatory plan or arrangement