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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2002
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-9498
MISSION RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0437769
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1331 Lamar, Suite 1455, Houston, Texas 77010-3039
(Address of principal executive offices) (Zip Code)
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. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [_]
The aggregate market value of the voting stock held by non-affiliates of the
registrant at June 28, 2002 was approximately $25,313,355.
As of March 20, 2003, the number of outstanding shares of the registrant's
common stock was 23,585,959.
Documents Incorporated by Reference: Portions of the registrant's annual
proxy statement, to be filed within 120 days after December 31, 2002, 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, 2002
TABLE OF CONTENTS
Page
Number
------
PART I
Item 1 Business.................................................................. 3
Item 2. Properties................................................................ 11
Item 3. Legal Proceedings......................................................... 22
Item 4. Submission of Matters to a Vote of Security Holders....................... 22
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..... 23
Item 6. Selected Financial Data................................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.............................................................. 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................ 40
Item 8. Financial Statements and Supplementary Data............................... 42
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.............................................................. 83
PART III
Item 10. Directors and Executive Officers of the Registrant........................ 83
Item 11. Executive Compensation.................................................... 83
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Shareholder Matters..................................................... 83
Item 13. Certain Relationships and Related Transactions............................ 83
Item 14. Controls and Procedures................................................... 83
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......... 84
Signatures....................................................................... 90
2
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
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.
Item 1. Business
General
Mission Resources Corporation is an independent oil and gas exploration and
production company headquartered in Houston, Texas. We acquire, develop and
produce crude oil and natural gas primarily along the Texas and Louisiana Gulf
Coast, in the Permian Basin of West Texas, in both the state and federal waters
of the Gulf of Mexico, and in East Texas. At December 31, 2002, our estimated
net proved reserves, using constant prices which were in effect at such date,
totaled 22.6 million barrels ("MMBBL") of oil, 2.0 MMBBL of natural gas liquids
("NGL"), and 81.5 billion cubic feet ("BCF") of natural gas for a total of 38.2
million barrels of oil equivalent ("MMBOE"). Approximately 64% of the estimated
net proved reserves were oil or NGL, and approximately 77% of the reserves were
developed.
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Terms specific to the 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.
Business Strategy
In 2002, new management was put in place with the goals of refinancing and
repositioning Mission's balance sheet, geographically focusing its activities,
and growing its assets and cashflow through the exploration and development of
oil and gas reserves. Our business strategy contains several important elements:
. Reposition the balance sheet to reduce financial leverage and increase
flexibility--We completed the first step toward this goal by acquiring,
in a private transaction, $97.6 million of the 10 7/8% senior
subordinated notes for approximately $71.7 million plus accrued interest.
The transaction, net of fees, reduced our overall debt by $17.6 million
and provided approximately $5.0 million for general corporate purposes.
We believe that further debt reduction is necessary to bring our leverage
to a more appropriate level and therefore, we are considering a number of
next step alternatives in our effort to further reduce leverage.
Simultaneous with the buyback, Mission amended and restated its credit
facility with new lenders.
. Establish natural gas as our primary product--Our exploration and
development program is specifically targeting natural gas production in
several producing regions: South Texas, the Texas and Louisiana Gulf
Coast, and the Permian Basin. Our goal is to move toward a 70% gas, 30%
oil production mix.
. Build an in-house exploration and evaluation capability by growing our
technical staff of geologists, geophysicists, and engineers who have
expertise in the geographic basins we have targeted--In addition, we are
utilizing an existing 3-D seismic library and continue to add to our
knowledge base through reprocessing of that data as well as the
acquisition and evaluation of new data. We believe that future growth in
our segment of the industry is technology driven using seismic
reprocessing, new seismic shoots, reservoir simulation, and sophisticated
drilling and completion techniques.
. Continue development and exploitation of our existing reserves to
maximize value especially in some of our more mature properties--We
undertook an extensive evaluation and rationalization effort during 2002,
divesting of $69.5 million of mature properties. In addition we engaged
Netherland, Sewell & Associates to perform a full evaluation of our
existing reserves. We have undertaken a program to fully develop these
reserves through the same technology that we are using in our exploration
programs.
. Protect cash flows by hedging a percentage of our proved producing
production for the current year and the two following years--The intent
is to hedge a higher percentage of our production in the current year, to
mitigate near term risk, with decreasing percentages in the following two
years. We may be limited in the amount of hedge transactions due to
credit constraints.
. Maintain control of administrative and operational functions to maximize
efficiencies--In 2002, the accounting, treasury, land administration,
human resources and risk management functions were brought in-house. We
have continued this strategy into 2003 by terminating outsource
agreements for marketing and operations of oil and gas properties. We
intend to be the operator of all joint properties whenever possible.
Oil and Gas Activities
Divestitures
During 2002, we sold several properties at auction and in negotiated sales.
The gross proceeds of these sales were approximately $69.5 million,
representing the sale of approximately 15.2 MMBOE of proved reserves. After
costs of the sales, the remaining proceeds were used to temporarily repay bank
borrowings and to pay interest on our 10 7/8% senior subordinated notes.
Our gross proceeds from property sales during 2001 totaled approximately
$40.0 million. We sold several domestic oil and gas properties and our
interests in Ecuadorian oil fields, representing approximately 14.3 MMBOE of
proved reserves. We also sold our interests in the Snyder and Diamond M gas
plants. With the sale of the Ecuadorian interests, we were relieved of
approximately $35.0 million in capital commitments related to those properties.
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Merger
On May 16, 2001, Bellwether Exploration Company ("Bellwether") merged with
Bargo Energy Company ("Bargo") and changed its name to Mission Resources
Corporation. At that time, we increased our authorized capital stock to 60.0
million shares of common stock and 5.0 million shares of preferred stock, and
amended the 1996 Stock Incentive Plan to increase the number of shares reserved
for issuance under the plan by 2.0 million shares. Under the merger agreement,
holders of Bargo's stock and options received a combination of cash and Mission
common stock. The merger was accounted for using the purchase method of
accounting. See the "Statements of Cash Flow" section of Note 2 to the
consolidated financial statements for the purchase price allocation and net
cash.
Mission issued $125.0 million of additional senior subordinated notes on May
29, 2001 and used most of the net proceeds of the note issuance to reduce
existing borrowings under the new credit facility.
Markets and Customers
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
that we produce or that we can obtain favorable prices for the oil and gas we
produce. In view of the many uncertainties affecting the supply of and demand
for oil, gas and refined petroleum products, neither future oil and gas prices
nor the demand for such products is predictable. Therefore, the significant
affect such prices and demand will have on our company are also unpredictable.
From time to time we may enter into crude oil and natural gas price collars,
swaps or other similar hedge transactions to reduce our exposure to price
fluctuations. A full description of our hedges and related risks can be found
at Item 7A of this Form 10-K: "Quantitative and Qualitative Disclosures About
Market Risk."
For several years, a significant portion of our gas production was sold to
affiliates of Torch Energy Advisors, Inc ("Torch"). Our contract with Torch had
an initial three-year term that began December 1996 and was renewable month to
month after such term. It provided for payment of index pricing (tied to Inside
FERC postings) less gathering and transportation charges to point of delivery.
The contract was re-negotiated in mid-2001 to remove the index pricing
provision. There were no other significant delivery commitments and our
remaining oil and gas production was sold at market responsive pricing by
Torch, as our agent. In early 2002, we ceased selling gas to Torch and
thereafter used Torch as our agent to sell substantially all of our production
to third parties at market responsive pricing. We are ending our marketing
relationship with Torch on April 1, 2003 at which time our own employees will
market Mission's oil and gas production.
In 2001 and 2000, sales to Torch accounted for 32% and 24%, respectively, of
our oil and gas revenues. The changes in our marketing strategy discussed above
have freed us from significant reliance on any one customer.
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In 2002, no single customer accounted for more than 10% of our oil and gas
revenues. We do not believe that the loss of any single customer or contract
would materially affect Mission's business.
Regulation
Federal Regulations
Sales and Transportation of Gas--Historically, the sale or resale of natural
gas in interstate commerce has been regulated pursuant to the Natural Gas Act
of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and the
regulations promulgated hereunder by the Federal Energy Regulatory Commission
("FERC"). In the past, the federal government has regulated the prices at which
natural gas could be sold. Deregulation of natural gas sales by producers began
with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act, which removed all remaining NGA and NGPA price and
non-price controls affecting producer sales of natural gas effective January 1,
1993. Congress could, however, re-enact price controls in the future.
Mission's sales of natural gas are affected by the availability, terms and
cost of transportation. The rates, terms and conditions applicable to the
interstate transportation of gas by pipelines are regulated by the FERC under
the NGA, as well as under section 311 of the NGPA. Since 1985, the FERC has
implemented regulations intended to increase competition within the gas
industry by making gas transportation more accessible to gas buyers and sellers
on an open-access, non-discriminatory basis.
The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines
operating on or across the Outer Continental Shelf ("OCS") provide open-access,
non-discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, in which the FERC implemented the OCSLA, on
gatherers and other non-jurisdictional entities, the FERC has retained the
authority to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the OCS. FERC also issued Order No.
639, requiring that virtually all non-proprietary pipeline transporters of
natural gas on the OCS report information on their affiliations, rates and
conditions of service. Among the FERC's stated purposes in issuing such rules
was the desire to provide shippers on the OCS with greater assurance of
open-access services on pipelines located on the OCS and non-discriminatory
rates and conditions of service on such pipelines. A federal district court
recently determined that FERC has exceeded its statutory authority in
promulgating Order Nos. 639 and 639-A, and the court permanently enjoined FERC
from enforcing the orders. FERC has appealed the district court's decision.
FERC has announced several important transportation-related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000, concerning alternatives to its traditional
cost-of-service ratemaking methodology to establish the rates interstate
pipelines may charge for their services. The final rule revised FERC's pricing
policy and current regulatory framework to improve the efficiency of the market
and further enhance competition in natural gas markets.
Sales and Transportation of Oil--Sales of oil and condensate can be made at
market prices and are not subject at this time to price controls. The price
received from the sale of these products will be affected by the cost of
transporting the products to market. FERC regulations govern the rates that may
be charged by oil pipelines by use of an indexing system for setting
transportation rate ceilings. In certain circumstances, rules permit oil
pipelines to establish rates using traditional cost of service and other
methods of rate making.
Legislative Proposals--In the past, Congress has been very active in the
area of gas regulation. In addition, there are legislative proposals pending in
the state legislatures of various states, which, if enacted, could
significantly 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--In the event that we conduct operations on
federal, state or Indian oil and gas leases, such operations must comply with
numerous regulatory restrictions, including various
6
nondiscrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management ("BLM") or, in the case our OCS leases
in federal waters, Minerals Management Service ("MMS") or other appropriate
federal or state agencies. Mission's OCS leases in federal waters are
administered by the MMS and require compliance with detailed MMS regulations
and orders.
Such leases are issued through competitive bidding, contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the OCSLA that are subject to interpretation and change by
the MMS. For offshore operations, lessees must obtain MMS approval for
exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications. The MMS also has regulations
restricting the flaring or venting of natural gas, and has proposed to amend
such regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization. Similarly, the MMS has promulgated other regulations
governing the plugging and abandonment of wells located offshore and the
installation and removal of all production facilities. 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 or other surety can be
substantial, and 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. Under some circumstances, the MMS may require any of
our operations on federal leases to be suspended or terminated. Any such
suspension or termination could materially adversely affect Mission's financial
condition and results of operations.
On March 15, 2000, the MMS issued a final rule effective June 2000, which
amended its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. Among other matters, this
rule amends the valuation procedure for the sale of federal royalty oil by
eliminating posted prices as a measure of value and relying instead on arm's
length sales prices and spot market prices as market value indicators. Because
Mission sells most of its production at spot market prices and, therefore, pays
royalties on production from federal leases based on spot prices, it is not
anticipated that this final rule will have a material impact on Mission.
The Mineral Leasing Act of 1920 (the "Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a
"non-reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect.
We own interests in numerous federal onshore oil and gas leases. It is possible
that our common stock will be acquired by citizens of foreign countries, which
at some time in the future might be determined to be non-reciprocal under the
Mineral Act.
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
7
. the prevention of waste of oil and gas resources, and
. the plugging and abandonment of wells.
The rate of production may be regulated and the maximum daily production
allowable from both oil and gas wells may be established on a market demand or
conservation basis or both.
Mission owns certain natural gas pipeline facilities that we believe meet
the traditional tests the FERC has used to establish a pipeline's status as a
gatherer not subject to FERC jurisdiction under the NGA. State regulation of
gathering facilities generally includes various safety, environmental, and in
some circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation.
Environmental Regulations
General--Our activities are subject to existing federal, state and local
laws and regulations governing environmental quality and pollution control. Our
activities with respect to exploration, drilling and production from wells,
natural gas facilities, including the operation and construction of pipelines,
plants and other facilities for transporting, processing, treating or storing
gas and other products, are subject to stringent environmental regulation by
state and federal authorities including the Environmental Protection Agency
("EPA"). Risks are inherent in oil and gas exploration and production
operations, and we can give no assurance that significant costs and liabilities
will not be incurred in connection with environmental compliance issues.
Neither can we predict what effect future regulation or legislation,
enforcement policies issued thereunder, and claims for damages to property,
employees, other persons and the environment resulting from our operations
could have.
Solid and Hazardous Waste--Mission currently owns or leases, and has in the
past owned or leased, numerous properties that for many years have been used
for the exploration and production of oil and gas. Although we utilized
operating and waste disposal practices that were standard in the industry at
the time, hydrocarbons or other solid wastes may have been disposed or released
on or under the properties we currently own or lease or on or under properties
that we once owned or leased. In addition, many of these properties are or have
been operated by third parties over whom we had no control as to their
treatment of hydrocarbons or other solid wastes and the manner in which such
substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under recent laws, we could be required to remove or remediate
previously disposed wastes (including wastes disposed or released by prior
owners or operators) or property contamination (including groundwater
contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future contamination.
Mission generates wastes, including hazardous wastes, that are subject to
the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the disposal
options for certain wastes, including wastes designated as hazardous under RCRA
and state analogs ("Hazardous Waste"). Furthermore, it is possible that certain
wastes generated by our oil and gas operations that are currently exempt from
treatment as Hazardous Waste may in the future be designated as Hazardous Waste
under RCRA or other applicable statutes, and therefore be subject to more
rigorous and costly operating and disposal requirements.
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
8
response to threats to the public health or the environment and to seek to
recover from the PRPs the costs of such action. Although CERCLA generally
exempts "petroleum" from the definition of Hazardous Substances, in the course
of its operations, Mission has generated and will generate wastes that may be a
CERCLA Hazardous Substance. We may also own or operate sites on which Hazardous
Substances have been released. Mission may be responsible under CERCLA for all
or part of the costs of investigation, remediation, and natural resource
damages at sites where Hazardous Substances have been released. We have not
been named a PRP under CERCLA nor do we know of any prior owners or operators
of our properties that are named as PRPs related to their ownership or
operation of such properties.
Clean Water Act--The Clean Water Act ("CWA") imposes restrictions and strict
controls regarding the discharge of wastes, including produced waters and other
oil and natural gas wastes, into waters of the United States, a term broadly
defined and including wetlands. These controls have become more stringent over
the years, and it is probable that additional restrictions will be imposed in
the future. Permits must be obtained to discharge pollutants into waters of the
United States. The CWA and OPA require facilities that store or otherwise
handle oil in excess of specified quantities to prepare and implement spill
prevention, control and countermeasure plans and facility response plans
relating to possible discharges of oil to surface waters. The CWA provides for
civil, criminal and administrative penalties for violations, including
unauthorized discharges of pollutants and of oil or hazardous substances. State
laws governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In the event of an unauthorized discharge of wastes, Mission may be liable for
penalties and costs.
Oil Pollution Act--The Oil Pollution Act of 1990 ("OPA"), which amends and
augments oil spill provisions of CWA, imposes certain duties and liabilities on
certain "responsible parties" related to the prevention of oil spills and
damages resulting from such spills in United States waters and adjoining
shorelines. A "responsible party" includes the owner or operator of a facility
or vessel that is a source of an oil discharge or poses the substantial threat
of discharge, or the lessee or permittee of the area in which a discharging
facility covered by OPA is located. OPA assigns joint and several liability,
without regard to fault, to each responsible party for oil removal costs and a
variety of public and private damages. Few defenses exist to the liability
imposed by OPA. In the event of an oil discharge or substantial threat of
discharge, Mission may be liable for costs and damages.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in the event of
a potential spill. The OPA requires owners and operators of offshore facilities
that have a worst case oil spill potential of more than 1,000 barrels to
demonstrate financial responsibility in amounts ranging from $10 million in
specified state waters and $35 million in federal OCS waters, with higher
amounts, up to $150 million based upon worst case oil spill discharge volume
calculations. We believe that we currently have established adequate proof of
financial responsibility for our offshore facilities.
Air Emissions--Mission's operations are subject to local, state and federal
regulations for the control of emissions of air pollution. Federal and State
laws require new and modified sources of air pollutants to obtain permits prior
to commencing construction. Major sources of air pollutants are subject to more
stringent requirements including additional permits. Particularly stringent
requirements may be imposed on major sources located in non-attainment areas
designated as not meeting National Ambient Air Quality Standards established by
the EPA. Administrative enforcement actions for failure to comply strictly with
air pollution regulations or permits are generally resolved by payment of
monetary fines and correction of any identified deficiencies. Alternatively,
regulatory agencies may bring lawsuits for civil or criminal penalties or
require us to forego construction, modification or operation of certain air
emission sources.
Coastal Coordination--There are various federal and state programs that
regulate the conservation and development of coastal resources. The federal
Coastal Zone Management Act ("CZMA") was passed in 1972 to preserve and, where
possible, restore the natural resources of the Nation's coastal zone. The CZMA
provides for federal grants for state management programs that regulate land
use, water use and coastal development.
9
In Texas, the Texas Legislature enacted the Coastal Coordination Act in 1991
("CCA"). The CCA provides for the coordination among local and state
authorities to protect coastal resources through regulating land use, water,
and coastal development. The act establishes the Texas Coastal Management
Program ("CMP"). The CMP is limited to the nineteen counties that border the
Gulf of Mexico and its tidal bays. The act provides for the review of state and
federal agency rules and agency actions for consistency with the goals and
policies of the Coastal Management Plan. This review may impact agency
permitting and review activities and add an additional layer of review to
certain activities that we undertake.
In Louisiana, state legislation enacted in 1978 established the Louisiana
Coastal Zone Management Program ("LCZMP") to protect, develop and, where
feasible, restore and enhance coastal resources of the state. Under the LCZMP,
coastal use permits are required for certain activities in the coastal zone,
even if the activity only partially infringes on the coastal zone. The Coastal
Management Division of Louisiana's Department of Natural Resources administers
the coastal use permit program which applies in coastal areas of 18 of
Louisiana's 64 parishes. Activities requiring such a permit include, among
other things, projects involving use of state lands and water bottoms, dredge
or fill activities that intersect with more than one body of water, mineral
activities, including the exploration and production of oil and gas, and
pipelines for the gathering, transportation or transmission of oil, gas and
other minerals. General permits, which entail a reduced administrative burden,
are available for a number of routine oil and gas activities. The LCZMP and its
requirement to obtain coastal use permits may result in additional permitting
requirements and associated time constraints for our projects.
OSHA and other Regulations--We are subject to the requirements of the
federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The OSHA hazard communication standard, the Environmental Protection
Agency community right-to-know regulations under Title III of CERCLA and
similar state statutes require Mission to organize and/or disclose information
about hazardous materials used or produced in its operations. We believe that
we are in substantial compliance with these 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.
Competition
We compete with other oil and gas companies in all areas of our operations,
including the acquisition of reserves and producing properties and the
marketing of oil and gas. Many of these companies may have greater financial
and other resources, which may adversely affect our ability to compete with
these companies. Our ability to compete for producing properties is dependent
upon the amount of funds we have available, the information available about a
producing property and our ability to analyze it, and the minimum projected
return on investment we are seeking.
Employees
At December 31, 2002, we were party to a Master Service Agreement ("MSA")
dated October 1, 1999, and two service contracts that required Torch to operate
oil and gas properties and market 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 and as a result at February 28, 2003 we
had 90 employees. The MSA will effectively terminate on April 1, 2003 because
all previous service contracts will have been terminated as of that date. In
addition to the services of our full time employees, we utilize the services of
independent contractors to perform certain services. We believe that our
relationships with our employees are satisfactory. None of our employees are
covered by a collective bargaining agreement.
10
Item 2. Properties
Oil and Gas Properties
Our oil and gas properties are primarily located along the Texas and
Louisiana Gulf Coast, in the Permian Basin of West Texas, in both state and
federal waters of the Gulf of Mexico and in East Texas. The following table
provides summary statistics about our properties as of December 31, 2002.
Gulf Permian Gulf of East Other
Coast Basin Mexico Texas (1)
------- --------- ------- ------- -----
Percent Oil/Gas..................... 39/61 80/20 38/62 95/5 75/25
# of Economical Gross/Net Wells..... 253/151 1,654/266 261/49 208/186 145/51
Percent of SEC PV-10(2)............. 41 39 8 10 2
Average Reserve Life (years)........ 8 9 3 7 4
Percent Approximate Working Interest 50 20 21 85 (3)
- --------
(1) Includes isolated property interests in California, Wyoming, Oregon, and
Oklahoma.
(2) In accordance with Securities and Exchange Commission requirements, the
estimated discounted future net cash flows are based on prices and costs as
of the date of the estimate. The average prices for natural gas and oil
used in our estimate were $4.74 per MMBTU and $31.17 per BBL on December
31, 2002, respectively.
(3) Approximate working interest would not be representative because the
properties are so diverse.
Reserves and Production
Reserves
Our estimated net proved oil and gas reserves at December 31, 2002 were 38.2
MMBOE, representing a decrease of approximately 43% from December 31, 2001
levels. The changes in proved reserves are summarized on the table below:
MMBOE
-----
Proved reserves at beginning of year 67.3
Revisions of previous estimates..... (8.7)
Extensions and discoveries.......... 0.3
Production.......................... (5.5)
Sales of reserves in-place.......... (15.2)
Purchase of reserves in-place....... --
-----
Proved reserves at end of year...... 38.2
=====
Mission has not filed oil or gas reserve information with any foreign
government or federal authority or agency that contain reserve information
materially different than those presented herein.
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 and assumptions, 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 substantially.
Mission's actual production, revenues, severance and excise taxes and
development and
11
operating expenditures with respect to its reserves will vary from such
estimates, and such variances could be material.
Estimates with respect to proved reserves that may be developed and produced
in the future are often based upon volumetric calculations and upon analogy to
similar types of reserves rather than actual production history. Estimates
based on these methods are generally less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be substantial, in the
estimated reserves.
In accordance with applicable requirements of the Securities and Exchange
Commission, the discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless prices or
costs subsequent to that date are contractually determined. Actual future
prices and costs may be materially higher or lower than prices or costs as of
the date of the estimate. Actual future net cash flows also will be affected by
factors such as actual production, supply and demand for oil and natural gas,
curtailments or increases in consumption by natural gas purchasers, changes in
governmental regulations or taxation and the impact of inflation on costs.
Production
The following table sets forth our production and reserve information as of
and for the year ended December 31, 2002 by area.
Net Production Estimated Net Proved Reserves
------------------------- ----------------------------- Discounted
Oil & Oil Oil & Oil Future Net
NGL Gas Equivalent NGL Gas Equivalent Cash
Area (MBBLS) (MMCF) (MBOE) (MBBLS) (MMCF) (MBOE) Flows(1)
---- ------- ------ ---------- ------- ------ ---------- ----------
($000's)
Gulf Coast.... 740 5,365 1,634 4,818 45,584 12,415 $132,366
Gulf of Mexico 320 3,662 930 1,165 11,418 3,068 25,274
Permian Basin. 1,413 2,106 1,764 12,996 19,618 16,266 128,589
East Texas.... 541 317 594 3,933 1,341 4,156 33,128
Other......... 409 1,074 588 1,698 3,529 2,286 7,545
----- ------ ----- ------ ------ ------ --------
3,423 12,524 5,510 24,610 81,490 38,191 $326,902
===== ====== ===== ====== ====== ====== ========
- --------
(1) In accordance with Securities and Exchange Commission requirements, the
estimated discounted future net cash flows are based on prices and costs as
of the date of the estimate. The average prices for natural gas and oil
used in our estimate were $4.74 per MMBTU and $31.17 per BBL on December
31, 2002, respectively.
Data relating to production volumes, average sales prices, average unit
production costs and oil and gas reserve information appears in Note 16 of the
Notes to Consolidated Financial Statements.
Acreage
Undeveloped acreage is considered to be 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. A gross acre in the following table refers to
the 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. A net acre is deemed to exist when the sum of fractional ownership
of working interests in gross acres equals one. All of our developed and
undeveloped acreage is domestic.
12
The following table sets forth information concerning our developed and
undeveloped oil and gas acreage as of December 31, 2002.
Gross Net
------- -------
Developed Acreage:
Gulf Coast........................ 45,676 16,517
Gulf of Mexico.................... 177,291 35,560
Permian Basin..................... 102,264 15,703
East Texas........................ 2,236 1,808
Other............................. 58,157 8,702
------- -------
Total Developed Acreage....... 385,624 78,290
------- -------
Undeveloped Acreage:
Gulf Coast........................ 13,389 7,444
Gulf of Mexico.................... 52,785 17,935
Permian Basin..................... 19,126 4,195
East Texas........................ -- --
Other............................. 72,819 31,485
------- -------
Total Undeveloped Acreage..... 158,119 61,059
------- -------
Total Acreage................. 543,743 139,349
======= =======
We believe that our title to oil and gas properties is good and defensible
in accordance with standards generally accepted in the oil and gas industry,
subject to exceptions which, in our opinion, are not so material as to detract
substantially from the use or value of the properties. 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.
See "Risk Factors" for a discussion of reserve estimates.
13
Productive Wells
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. A "net well" is deemed
to exist when the sum of fractional ownership working interests in gross wells
equals one.
The following table sets forth the number of productive oil and gas wells in
which we own interests as of December 31, 2002.
Gross Net
----- ---
Oil Wells:
Gulf Coast.............. 142 104
Gulf of Mexico.......... 69 13
Permian Basin........... 943 119
East Texas.............. 204 185
Other................... 117 23
----- ---
Total Oil Wells..... 1,475 444
----- ---
Gas Wells:
Gulf Coast.............. 111 47
Gulf of Mexico.......... 192 36
Permian Basin........... 711 147
East Texas.............. 4 1
Other................... 28 28
----- ---
Total Gas Wells..... 1,046 259
----- ---
Total Wells......... 2,521 703
===== ===
Drilling Activity
Our principal drilling activities during the last three fiscal years were
focused on properties along the Texas and Louisiana Gulf Coast, in the Gulf of
Mexico, and in Oregon and the Permian Basin in New Mexico. Our development of
the Charapa and Tiguino fields in Ecuador accounted for all international
drilling activities.
The following tables set forth the results of drilling activity for the last
three fiscal years:
Exploratory Wells
Gross Net
---------------------- ----------------------
Dry Dry
Productive Holes Total Productive Holes Total
---------- ----- ----- ---------- ----- -----
2000--Domestic 7 6 13 3.98 1.96 5.94
2000--Ecuador. -- -- -- -- -- --
2001--Domestic 2 6 8 0.92 1.13 2.05
2002--Domestic 4 1 5 1.66 .07 1.73
Development Wells
Gross Net
---------------------- ----------------------
Dry Dry
Productive Holes Total Productive Holes Total
---------- ----- ----- ---------- ----- -----
2000--Domestic 46 8 54 15.01 2.70 17.71
2000--Ecuador. 1 3 4 0.70 2.70 3.40
2001--Domestic 48 7 55 14.24 5.13 19.37
2002--Domestic 29 3 32 10.03 1.11 11.14
Three domestic wells were in progress as of December 31, 2002.
14
Gas Plants
In late 2001, we sold our interests in the Snyder and Diamond M Gas Plants
for gross proceeds of $11.5 million. The Point Pedernales Gas Plant, located in
California, is operated by Nuevo Energy Company in conjunction with the Point
Pedernales field from which the processed gas is produced. We no longer report
our 19.7% interest in this plant separately, primarily because it does not
process gas from third parties and therefore does not generate revenue apart
from the related Point Pedernales field. The revenues and expenses of the plant
are reported as NGL revenue and part of production expenses for the Point
Pedernales field. The plant is included as part of our full cost pool for
purposes of calculating depreciation. The Point Pedernales field, including
this gas plant was sold in March 2003 to the operator. We paid them $1.8
million to assume the environmental, plugging and abandonment liabilities
estimated to be between $3 million and $5 million.
Risk Factors
Risks Related to Our Business, Industry and Strategy
Our success depends upon our ability to replace reserves.
Our future performance depends upon our ability to find, develop and acquire
additional oil and gas reserves that are economically recoverable. Our proved
reserves will generally decline as those reserves are depleted. We therefore
must locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. We cannot assure you that we will be able to find
and develop or acquire additional reserves at an acceptable cost.
Oil and gas prices fluctuate widely, and low prices could have a material
adverse impact on our business and financial results.
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include:
. weather conditions in the United States;
. the condition of the United States economy;
. the actions of the Organization of Petroleum Exporting Countries;
. domestic and foreign governmental regulation;
. political stability in the Middle East and elsewhere;
. the foreign supply of oil and gas;
. the price of foreign imports; and
. the availability of alternate fuel sources.
Any substantial and extended decline in the price of oil or gas would have
an adverse effect on the carrying value of our proved reserves, our borrowing
capacity, our ability to obtain additional capital, and our revenues,
profitability and cash flows. Lower prices may also reduce the amount of oil
and natural gas that we can produce economically and require us to record
ceiling test write-downs when prices decline.
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.
15
We cannot assure you that such transactions will reduce the risk or minimize
the effect of any decline in oil or natural gas prices.
We may not be able to market all or obtain favorable prices for the oil or gas
we produce.
Our ability to market oil and gas from our wells depends upon numerous
domestic and international factors beyond our control, including:
. the extent of domestic production and imports of oil and gas;
. the proximity of gas production to gas pipelines;
. the availability of capacity in such pipelines;
. the demand for oil and gas by utilities and other end users;
. the availability of alternate fuel sources;
. the effects of inclement weather;
. state, federal and international regulation of oil and gas production; and
. federal regulation of gas sold or transported in interstate commerce.
We cannot assure you that we will be able to market all of the oil or gas we
produce or that we can obtain favorable prices for the oil and gas we produce.
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 addition,
reserve engineers may make different estimates of reserves and cash flows based
on the same available data. In calculating reserves on an oil equivalent basis,
gas was converted to oil equivalent at the ratio of one BBL of oil to six MCF
of gas. While this ratio approximates the energy equivalency of oil to gas 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
16
changes in consumption by natural gas purchasers or in governmental regulations
or taxation may also affect actual future net cash flows. The timing of both
the production and the expenses from the development and production of oil and
natural gas properties will affect the timing of actual future net cash flows
from proved reserves and their present value. In addition, the 10% discount
factor, which is required by the Securities and Exchange Commission to be used
in calculating discounted future net cash flows for reporting purposes, is not
necessarily the most accurate discount factor. The effective interest rate at
various times and the risks associated with our operations or the oil and
natural gas industry in general will affect the accuracy of the 10% discount
factor.
Lower oil and natural gas prices may cause us to record ceiling test
write-downs.
We use the full cost method of accounting to account for our oil and natural
gas operations. Accordingly, we capitalize the cost to acquire, explore for and
develop oil and natural gas properties. Under full cost accounting rules, the
net capitalized costs of oil and natural gas properties may not exceed a
"ceiling limit" which is based upon the present value of estimated future net
cash flows from proved reserves, discounted at 10%, plus the lower of cost or
fair market value of unproved properties. If net capitalized costs of oil and
natural gas properties exceed the ceiling limit, we must charge the amount of
the excess to earnings. This is called a "ceiling test write-down." This charge
does not impact cash flow from operating activities, but does reduce our
stockholders' equity. The risk that we will be required to write down the
carrying value of oil and natural gas properties increases when oil and natural
gas prices are low or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves.
We face strong competition from larger oil and gas companies that may
negatively affect our ability to carry on operations.
The oil and gas business is highly competitive. Many competitors have
substantially larger financial resources, staffs and facilities than we do.
These larger competitors include independent oil and gas producers such as
Apache Corporation, Burlington Resources, Inc., Anadarko Petroleum Inc., Ocean
Energy, Inc. and Devon Energy Corporation. Factors that affect our ability to
compete in the marketplace include:
. the availability of funds and information relating to a property;
. the standards established by us for the minimum projected return on
investment; and
. the availability of alternate fuel sources and the intermediate
transportation of oil and gas.
Risks Related to Financing Our Business
We may not be able to fund our planned capital expenditures.
We make, and will continue to make, substantial capital expenditures for the
exploitation, exploration, acquisition and production of oil and gas reserves.
Our capital expenditures were $21.4 million during 2002, $72.2 million during
2001 and $88.4 million during 2000. We have budgeted total capital expenditures
in 2003 of approximately $32.0 million, however, if commodity prices continue
at the current level, the capital expenditure budget will increase. Our plan is
to budget capital expenditures up to discretionary cash flows. 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, bank credit facility
borrowings, and the sales of oil and gas properties. We believe that our
working capital and operating cash flow will be sufficient to meet planned
capital expenditures in 2003. If revenues or our borrowing base decrease as a
result of lower oil and gas prices, operating difficulties or declines in
reserves, we may have limited ability to expend the capital necessary to
undertake our 2003 exploration and development program. We cannot assure you
that additional debt or equity financing or cash generated by operations or oil
and gas property sales will be available to meet these requirements.
17
We have a highly leveraged capital structure, which limits our financial
flexibility.
We have a highly leveraged capital structure due to our outstanding 10 7/8%
senior subordinated notes due 2007, 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
$24.0 million annually, 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 require us to meet certain
financial tests, and other restrictions limit our ability to borrow
additional funds or dispose of assets and may affect our flexibility in
planning for, and reacting to, changes in our business, including
possible acquisition activities; and
. our ability to obtain financing in the future for working capital,
capital expenditures, acquisitions, general corporate purposes or other
purposes may be impaired.
Our ability to meet our debt service obligations and to reduce our total
indebtedness will be dependent upon future performance, which will be subject
to general economic conditions and to financial, 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.
Because of these issues, our new management team has undertaken a review of
the various alternatives to restructure Mission and has retained the
investment-banking firm of Petrie Parkman & Co. to assist in this evaluation.
Among the alternatives being considered are
. a refinancing of the notes;
. a new credit facility;
. a merger with or an acquisition by another company;
. the sale of certain oil and gas properties;
. the acquisition by Mission of another company or assets;
. the addition of other secured and unsecured debt financings; and
. the issuance of equity securities or other debt securities for cash or
properties or in exchange for the notes.
Some of these alternatives would require approval of our stockholders, and
all of them will require the approval of other parties to the transaction. We
cannot assure you that we will be successful in completing any of these
possible transactions.
Hedging production may limit potential gains from increases in commodity prices
or result in losses.
We may, from time to time, reduce our exposure to the volatility of oil and
gas prices by hedging a portion of our production. In a typical hedge
transaction, we will have the right to receive from the counter party to the
hedge, the excess of the fixed price specified in the hedge over a floating
price based on a market index, multiplied by the quantity hedged. If the
floating price exceeds the fixed price, we are required to pay the counter
party this difference multiplied by the quantity hedged. In such case, we are
required to pay the difference regardless of whether we had sufficient
production to cover the quantities specified in the hedge. Significant
reductions in production at times when the floating price exceeds the fixed
price could require us to make payments under the hedge agreements even though
such payments are not offset by sales of production. Hedging will also prevent
us from receiving the full advantage of increases in oil or gas prices above
the fixed amount specified in the hedge.
18
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
Senior Vice President and Chief Financial Officer, John L. Eells, our Senior
Vice President--Exploration and Geoscience, and Joseph G. Nicknish, our Senior
Vice President--Operations and Engineering. 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 which occur in the marine environment, such as hurricanes or
other adverse weather conditions, to more extensive governmental regulation,
including regulations that may, in certain circumstances, impose strict
liability for pollution damage, and to interruption or termination of
operations by governmental authorities based on environmental or other
considerations.
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.
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
19
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, and is vigorously defending these claims to avoid this
liability. At this time, it is not possible to determine the amount of
potential exposure that we may have for these 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/or 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/or Nuevo. The amount of
bonds presently issued to Torch and Nuevo pursuant to these agreements is
approximately $35.2 million. 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.
Compliance with environmental and other government regulations is costly and
could negatively impact production.
Our operations are subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. For a discussion of material regulations applicable
to us, see "Regulation--Federal Regulations," "--State Regulations," and
"--Environmental Regulations." These laws and regulations:
. require the acquisition of a permit before drilling commences;
. restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;
. limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas;
. require remedial measures to mitigate pollution from former operations,
such as plugging abandoned wells; and
. impose substantial liabilities for pollution resulting from our
operations.
The recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. The enactment of stricter legislation or the
adoption of stricter regulations could have a significant impact on our
operating costs, as well as on the oil and gas industry in general.
The Oil Pollution Act of 1990 imposes a variety of regulations on
"responsible parties" related to the prevention of oil spills. The
implementation of new, or the modification of existing, environmental laws or
regulations, including regulations promulgated pursuant to the Oil Pollution
Act of 1990, could have a material adverse impact on us.
Risks Related to Our Common Stock Outstanding
Our stock price could be 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
20
announcements concerning changes in prices of oil and natural gas, the success
of our exploration and development drilling program, the availability of
capital, and economic and other external factors, as well as period-to-period
fluctuations and financial results, may have a significant effect on the market
price of our common stock.
The lack of trading volume and the possible delisting of our common stock could
adversely affect the prevailing market for our common stock.
Historically, there has been limited trading volume for our common stock. On
January 28, 2003, we received a Nasdaq Staff Determination indicating that
Mission had failed to comply with Nasdaq's minimum bid price requirement of
$1.00 per share for continued listing of our common stock on The Nasdaq
National Market, and that, as a result, our common stock was subject to
delisting from The Nasdaq National Market at the opening of business on
February 6, 2003. We requested an oral hearing before a Nasdaq Listing
Qualifications Panel to review the Nasdaq Staff Determination. Prior to the
hearing date, proposed changes to Nasdaq's minimum bid price requirement were
approved, and Mission was granted an additional 90 days, or until April 28,
2003, to come into compliance with such requirement. Because of this change,
Nasdaq postponed the hearing pending a determination by Nasdaq regarding
Mission's compliance with the minimum bid price requirement after April 28,
2003. In the event Mission is unable to satisfy the bid price requirement by
April 28, 2003, the hearing process will re-commence. We cannot assure you that
Mission will be in compliance with the amended minimum bid price requirement by
April 28, 2003 or that a Nasdaq Listings Qualification Panel will grant
Mission's request for continued listing of our common stock on the Nasdaq
National Market System.
We are reviewing all options available to us to return to compliance with
Nasdaq's continued listing requirements. The delisting of our common stock from
Nasdaq may result in a reduction in some or all of the following, each of which
may have a material adverse effect on our investors:
. the market price of our common stock;
. the liquidity of our common stock;
. the number of institutional investors that will be allowed by their
charter to invest or consider investing in our common stock;
. the number of investors in general that will consider investing in our
common stock;
. the number of market makers in our common stock;
. the availability of information concerning the trading prices and volume
of our common stock;
. the number of broker-dealers willing to execute trades in shares of our
common stock; and
. our ability to obtain financing for the continuation of our operations.
We do not pay dividends.
We have never declared or paid any cash dividends on our common stock and
have no intention to do so in the near future. The restrictions on our present
or future ability to pay dividends are included in the provisions of the
Delaware General Corporation Law and in certain restrictive provisions in the
indentures executed in connection with our 10 7/8% senior subordinated notes
due 2007. In addition, our bank credit facility contains provisions that may
have the effect of limiting or prohibiting the payment of dividends.
Our certificate of incorporation and bylaws 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
shareholders rights plan and the provisions of the Delaware General Corporation
Law may encourage persons considering unsolicited tender
21
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. These provisions, alone or in
combination with each other and with the shareholder 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 shareholder 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 takeover that may be desired by a majority of our
stockholders or involving a premium over the prevailing stock price.
Item 3. Legal Proceedings
Mission is involved in litigation relating to claims arising of its
operations in the normal course of business, including workmen's compensation
claims, tort claims and contractual disputes. Some of the existing known claims
against us are covered by insurance subject to the limits of such policies and
the payment of deductible amounts by us. Management believes that the ultimate
disposition of all uninsured or unindemnified matters resulting from existing
litigation will not have a material adverse effect on Mission's business or
financial position.
Item 4. Submission of Matters to a Vote of Security Holders
None.
22
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Mission's common stock is traded on The Nasdaq National Market (Symbol:
MSSN).
On January 28, 2003, we received a Nasdaq Staff Determination indicating
that we had failed to comply with Nasdaq's minimum bid price requirement of
$1.00 per share for continued listing of our common stock on The Nasdaq
National Market. As a result, our common stock was subject to delisting from
The Nasdaq National Market at the opening of business on February 6, 2003. We
requested an oral hearing before a Nasdaq Listing Qualifications Panel to
review the Nasdaq Staff Determination.
Prior to the hearing date, proposed changes to Nasdaq's minimum bid price
requirement were approved, and Mission was granted an additional 90 days, or
until April 28, 2003, to come into compliance with such requirement. Because of
this change, Nasdaq postponed the hearing pending a determination by Nasdaq
regarding Mission's compliance with the minimum bid price requirement after
April 28, 2003. In the event Mission is unable to satisfy the bid price
requirement by April 28, 2003, the hearing process will re-commence. We cannot
assure you that Mission will be in compliance with the amended minimum bid
price requirement by April 28, 2003 or that a Nasdaq Listings Qualification
Panel will grant Mission's request for continued listing of our stock on the
Nasdaq National Market System.
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.
Sales Price
-----------
High Low
----- -----
Quarter Ended:
March 31, 2001..... $9.75 $7.56
June 30, 2001...... $9.00 $6.70
September 30, 2001. $6.00 $3.80
December 31, 2001.. $4.14 $2.90
March 31, 2002..... $3.57 $2.60
June 30, 2002...... $3.05 $1.35
September 30, 2002. $1.52 $0.48
December 31, 2002.. $0.80 $0.28
We have not paid dividends on our common stock and do not anticipate paying
cash dividends in the immediate future as we contemplate that our cash flows
will be used for continued growth of our operations. In addition, certain
covenants contained in our financing arrangements restrict the payment of
dividends (see Management's Discussion and Analysis of Financial Condition and
Results of Operations--Financing Activities and Note 8 of the Notes to
Consolidated Financial Statements). There were approximately 1,368 stockholders
of record as of March 20, 2003.
23
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).
Year Ended December 31,
------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
Gas revenues............................... $ 39,715 $ 57,705 $ 62,652 $ 41,559 $ 46,661
Oil revenues............................... 73,164 75,530 49,601 26,705 26,991
Gas plant revenues......................... -- 4,456 6,070 3,830 3,170
Interest and other income (loss)........... (7,415) 4,386 957 1,335 1,347
-------- -------- -------- -------- --------
Total revenues.......................... 105,464 142,077 119,280 73,429 78,169
Lease operating expense.................... 43,222 44,773 24,553 18,702 21,748
Taxes other than income.................... 9,246 6,656 6,273 3,072 4,012
Transportation costs....................... 834 73 270 316 435
Gas plant expenses......................... -- 2,118 2,677 2,366 1,967
Depreciation, depletion and amortization... 43,291 45,106 32,654 23,863 39,688
Impairment expense......................... 16,679 27,057 -- -- 73,899
Disposition of hedges...................... -- -- 8,671 -- --
Uncollectible gas revenues................. -- 2,189 -- -- --
Mining venture costs....................... -- 914 -- -- --
Loss on sale of assets..................... 2,645 11,600 -- -- --
General and administrative expenses........ 12,758 15,160 8,821 7,606 8,080
Interest expense........................... 26,853 23,664 15,375 11,845 11,660
Provision for income tax (benefit)......... (11,580) (9,055) (12,222) (3,154) (6,069)
-------- -------- -------- -------- --------
Total expenses.......................... 143,948 170,255 87,072 64,616 155,420
Cumulative effect of a change in accounting
method, net of deferred taxes............ -- 2,767 -- -- --
-------- -------- -------- -------- --------
Net income (loss).......................... $(38,484) $(30,945) $ 32,208 $ 8,813 $(77,251)
======== ======== ======== ======== ========
Earnings (loss) per common share........... $ (1.63) $ (1.54) $ 2.32 $ 0.64 $ (5.50)
Earnings (loss) per common share--diluted.. $ (1.63) $ (1.54) $ 2.27 $ 0.63 $ (5.50)
Working capital............................ $ 952 $ 105 $ 7,212 $ 3,770 $ 6,077
Long-term debt, net of current maturities.. $226,431 $261,695 $125,450 $130,000 $104,400
Stockholders' equity....................... $ 65,377 $110,240 $ 56,960 $ 23,314 $ 14,489
Total assets............................... $342,404 $447,764 $221,545 $171,761 $131,196
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
acquire, develop and produce crude oil and natural gas. Our balanced 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 is on property
enhancement through exploitation and development drilling, low to moderate risk
exploration, asset redeployment and operating cost reduction and acquisitions
when the opportunities are suitable. Our primary business objective is to
create value through expanding reserves and production that, in turn, results
in per-share increases in net asset value, cash flow and earnings.
Financing Activities
Our outstanding indebtedness totaled $225.0 million at December 31, 2002.
The entire amount was attributable to the 10 7/8% senior subordinated notes due
in 2007. We also had $40.0 million available for borrowing under a revolving
credit facility at December 31, 2002.
24
On May 16, 2001, Bellwether merged with Bargo and changed its name to
Mission Resources Corporation. At that time, we increased our authorized
capital stock to 60.0 million shares of common stock and 5.0 million shares of
preferred stock, and amended the 1996 Stock Incentive Plan to increase the
number of shares reserved for issuance under the plan by 2.0 million shares.
Under the merger agreement, holders of Bargo's stock and options received a
combination of cash and Mission common stock. We used the purchase method to
account for the merger.
The merger was financed through the issuance of $80.0 million in Mission
common stock to Bargo option holders and shareholders, and an initial draw down
under a credit facility of $166.0 million. The funds from the credit facility
were used to:
. refinance Bargo's and Bellwether's then existing credit facilities.
. pay the cash portion of the purchase price of the Bargo common stock and
options, and
. fund Bargo's redemption its preferred stock immediately prior to the
merger.
Mission issued $125.0 million of additional senior subordinated notes on May
29, 2001 and used most of the net proceeds of the bond issuance to reduce
existing borrowings under the credit facility.
Senior Subordinated Notes
In April 1997, we issued $100.0 million of 10 7/8% senior subordinated notes
due 2007. On May 29, 2001, we issued an additional $125.0 million of senior
subordinated notes due 2007, with identical terms to the notes issued in April
1997, at a premium of $1.9 million that is shown separately on the balance
sheet. We amortize the premium as a reduction of interest expense over the life
of the notes so that the effective interest rate on these additional notes is
10.5%. Through December 31, 2002, we had amortized approximately $445,000 of
the premium. Interest on the notes is payable semi-annually on April 1st and
October 1st. We believe that we have sufficient liquidity provided by cash
flows from operations, to pay the interest due on the notes.
We may choose to redeem the notes, in whole or in part, at any time after
April 1, 2000 at 105.44% plus accrued and unpaid interest. The redemption price
decreases annually to 100% on April 1, 2005. Should control of Mission change,
as defined in the note indenture, the note-holders could require us to purchase
from them all or part of the notes for 101% plus accrued and unpaid interest.
The notes contain covenants that:
. limit indebtedness and liens;
. require compliance with covenants of existing debt such as our credit
facility;
. limit dividend payments and repurchases of capital stock;
. restrict payments to subsidiaries defined by the indenture as restricted
subsidiaries;
. control issuance and sales of stock of restricted subsidiaries;
. restrict the disposition of proceeds from asset sales; and
. restrict mergers and consolidations or sales of assets.
We were in compliance with the covenants of the notes at December 31, 2002
and are currently in compliance. The notes require us to comply with covenants
of other existing debt if borrowings under that debt exceed $10.0 million.
Because our credit facility had no balance at December 31, 2002 and we do not
expect to exceed $10.0 million of borrowing under this facility in the first
quarter of 2003, any potential for non-compliance with its covenants will not
impact our compliance with the covenants of our notes.
Standard and Poor's and Moody's publish debt ratings for Mission. Their
ratings consider a number of items including, but not limited to, our debt
levels, planned asset sales, near-term and long-term production growth
25
opportunities, capital allocation challenges and commodity price levels. At
December 31, 2002, our Standard & Poor's corporate bond rating was "B" and our
Moody's rating was "Caa1, Negative Outlook". A decline in our ratings would not
create a default or other unfavorable change in the notes and credit facility.
Credit Facility
Mission is party to a $150.0 million credit facility with a syndicate of
lenders. The Credit Facility is a revolving facility, expiring May 16, 2004,
which allows Mission to borrow, repay and re-borrow under the facility from
time to time. The total amount that we may borrow is called our borrowing base.
The lenders periodically set the borrowing base based upon their consideration
of our oil and gas reserves or other factors they deem relevant. At December
31, 2002, our borrowing base was $40.0 million. The credit facility was
recently amended on October 7, 2002, reducing the maximum amount available
under the credit facility from $200.0 million to $150.0 million. This
modification does not limit the rights of the parties to initiate interim
borrowing base redeterminations in accordance with the credit facility. As a
result of the reduction in our borrowing capacity, $412,000 of previously
capitalized deferred financing costs was charged to interest expense.
We paid interest on the credit facility borrowings during 2002 at an average
interest rate of 3.9%. For future borrowings, we may elect to apply an annual
interest rate on credit facility borrowings equal to either:
. the Eurodollar rate, plus an applicable margin ranging from 1.5% to 2.5%;
or
. the greater of (i) the prime rate, as determined by Chase Manhattan Bank,
or (ii) the federal funds rate plus 0.5%, plus a maximum of 1.0%.
The applicable margin for interest is based on our outstanding borrowings as
a percentage of the borrowing base, and our long-term debt rating as published
by Standard & Poor's or Moody's.
We also pay commitment fees on funds available under the borrowing base and
fees on outstanding letters of credit. Commitment fees range from 0% to 0.5% on
the unused portion of the credit facility. Letter of credit fees range from 0%
to 2.5% of the unused portion of the $20.0 million letter of credit
sub-facility. Commitment fees and letter of credit fees under the credit
facility are based on our utilization rate and long-term debt rating.
The credit facility contains negative covenants that limit our ability,
among other things, to:
. incur additional debt;
. pay dividends on stock, redeem stock or redeem subordinated debt;
. make investments;
. create liens in favor of senior subordinated debt and subordinated debt;
. sell assets;
. sell capital stock of subsidiaries;
. guarantee other indebtedness;
. enter into agreements that restrict dividends from subsidiaries;
. merge or consolidate; and
. enter into transaction with affiliates.
26
In addition, the credit facility requires that we maintain certain financial
covenants:
. a minimum interest coverage ratio of earnings before interest,
depreciation, depletion, amortization, income tax, and extraordinary
items, or EBITDAX, to interest expense:
Fiscal Quarter Interest Coverage Ratio
-------------- -----------------------
09/30/02 through 03/31/03 1.75 to 1.00
04/01/03 through 06/30/03 1.90 to 1.00
07/01/03 through 09/30/03 2.10 to 1.00
10/01/03 through 12/31/03 2.30 to 1.00
01/01/04 and thereafter.. 2.50 to 1.00
. an asset coverage or current ratio (which includes availability) of at
least 1.0 to 1.0;
. a maximum ratio of senior debt to EBITDAX of 2.0 to 1.0; and
. a maximum ratio of total debt to EBITDAX:
Fiscal Quarter Total Debt to EBITDAX
-------------- ---------------------
09/30/02 through 12/31/02 5.50 to 1.00
01/01/03 through 03/31/03 5.00 to 1.00
04/01/03 through 06/30/03 4.75 to 1.00
07/01/03 through 09/30/03 4.50 to 1.00
10/01/03 through 12/31/03 4.00 to 1.00
01/01/04 and thereafter.. 3.50 to 1.00
We had no outstanding borrowings under the credit facility and were in
compliance with its covenants on December 31, 2002. At current oil and gas
price levels, we expect to be in compliance with all of the credit facility
covenants throughout 2003. 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.
Capital Structure
We have a highly leveraged capital structure, limiting our financial
flexibility. In particular, we must pay approximately $24 million of interest
annually on the notes, which limits the amount of cash provided by operations
that is available for exploration and development of oil and gas properties.
The notes also contain various covenants that limit our ability to, among other
things, incur additional indebtedness, pay dividends, purchase capital stock
and sell assets. In addition, our common stock is trading at historically low
levels, which limits our ability to complete offerings of equity securities.
Because of these issues, our new management team has reviewed various
alternatives to restructure the company and has retained the investment-banking
firm of Petrie Parkman & Co. to assist in this evaluation. Among the
alternatives being considered are
. a refinancing of the notes;
. a new credit facility;
. a merger with or an acquisition by another company;
. the sale of certain oil and gas properties;
. the acquisition by the company of another company or assets;
27
. the addition of other secured and unsecured debt financings; and
. the issuance of equity securities or other debt securities for cash or
properties or in exchange for the notes.
Some of these alternatives would require approval of our shareholders, and
all of them will require the approval of other parties to the transaction. We
cannot assure you that we will be successful in completing any of these
possible transactions.
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 bank
credit facility borrowings, the issuance of common stock, and the sale of
properties. Our primary uses of capital have been the funding of exploration
and development projects and property acquisitions.
Source of Capital: Operations
Cash flow provided by operating activities, which is calculated after taking
into account changes in working capital, totaled $7.2 million, $40.4 million
and $60.1 million for the fiscal years 2002, 2001, and 2000, respectively. Our
operating cash flow is sensitive to many variables, with prices of oil, natural
gas and NGL being the most volatile. Prices are determined primarily by
prevailing market conditions. Regional and worldwide economic growth, weather
and other variable factors influence market conditions. We are not able to
control these factors and may not be able to accurately predict prices.
To mitigate some of the risk inherent in oil and natural gas prices, we
hedge our oil and natural gas production by entering into commodity price swaps
or collars designed to set minimum and/or maximum prices on a portion of our
production. Our policy is to hedge a percentage of proved producing production
for the current year and the two following years.
We mitigate, but do not eliminate the potential negative effect of declining
prices on operating cash flow because these hedges remove the price volatility
from some of our oil and natural gas production. Hedging also prevents us from
receiving the full advantage of increases in oil or gas prices above the fixed
amount specified in the hedge.
See "Item 7A--Quantitative and Qualitative Disclosures About Market Risk"
for a more detailed discussion of commodity price risk and a listing of our
current hedges.
Source of Capital: Debt
Our outstanding balance under the 10 7/8% senior subordinated notes was
$225.0 million at December 31, 2002 and 2001 and was $100.0 million at the end
of 2000. No credit facility borrowings were outstanding at December 31, 2002.
Borrowings under our credit facility were $35.0 million and $25.5 million at
the end of 2001 and 2000, respectively. At December 31, 2002, $40.0 million was
available for borrowing under the credit facility. As previously discussed
under "Financing Activities," both our notes and our credit facility contain
covenants limiting our activities or requiring that we maintain specific
financial ratios. As of December 31, 2002, 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.
28
Source of Capital: Issuance of Common Stock
We issued 9.5 million shares of common stock on May 16, 2001 to holders of
Bargo stock and options in order to effect the merger. Simultaneously with the
merger, Mission's authorized capital stock was increased to 60.0 million shares
of common stock and 5 million shares of preferred stock.
Source of Capital: Sale of Properties
We continue to evaluate and assess our property portfolio and capital needs,
and we may from time to time sell certain properties as appropriate. Net
proceeds from the sale of domestic oil and gas properties were approximately
$60.4 million in 2002, $15.9 million in 2001 and $46.0 million in 2000. Net
proceeds are gross proceeds adjusted for transaction costs and interim
operations. We also sold our Ecuadorian interests for approximately $4.8
million in June 2001 and our Snyder and Diamond M gas plant interests for $10.9
million in late 2001.
Use of Capital: Exploration and Development
Mission's expenditures for exploration, including land and seismic costs,
and development of its domestic oil and gas properties totaled $20.6 million,
$44.6 million and $71.2 million, for the fiscal years 2002, 2001 and 2000,
respectively. We also spent $3.9 million in the year 2001 and $10.0 million in
the year 2000 on development of the Charapa and Tiguino fields in Ecuador.
Our capital budget for 2003 totals approximately $32.0 million, with $5.8
million for exploration, $20.8 million for development, and $5.4 million for
seismic data, land and related items. If commodity prices continue at the
current level, the capital expenditure budget will increase. Our plan is to
budget capital expenditures up to discretionary cash flows. This capital budget
represents the largest planned use of our available operating cash flow. We
believe that working capital and operating cash flow will be sufficient to meet
the exploration and development plans detailed in the budget. To a certain
degree, the ultimate timing of these capital expenditures is within our control.
Use of Capital: Acquisitions
We did not make any significant acquisitions during the year 2002. The
merger with Bargo, valued at $280.9 million, was the most significant
acquisition of 2001. Our other domestic property acquisitions totaled $23.5
million in the year 2001 and $7.1 million in the year 2000. Additionally, we
spent $249,000 in the year 2001 and $2.0 million in the year 2000 to acquire an
interest in the Tiguino field in Ecuador. The field was subsequently sold in
June 2001. We continuously review acquisition opportunities and would first
consider whether operating cash flows were adequate to make a desired
acquisition. For larger acquisitions, we would drawdown on our credit facility
or would attempt to issue equity securities, however, we cannot assure you that
either of these sources would be able to provide funds adequate to complete all
desired acquisitions.
Contractual Obligations and Commercial Commitments
Mission is required to make future payments under contractual obligations.
The following table details those payments (amounts in thousands):
Contractual Cash Obligations: Total 2003 2004 2005 2006 2007 Thereafter
- ----------------------------- -------- ------- ------- ------- ------- -------- ----------
Long Term Debt*.............. $328,993 $24,469 $24,469 $24,469 $24,469 $231,117 $--
Operating Leases............. 2,755 777 703 631 622 22 --
-------- ------- ------- ------- ------- -------- ---
Total Contractual Obligations $331,748 $25,246 $25,172 $25,100 $25,091 $231,139 $--
======== ======= ======= ======= ======= ======== ===
- --------
* Includes bond principal of $225.0 million scheduled for repayment in 2007 and
bond interest accrued monthly and payable April 1/st/ and October 1/st/ of
each year.
29
Mission has also made various commitments in the future should certain
events occur or conditions exist. The estimated payments related to those
commitments are scheduled on the table below (amounts in thousands):
Commercial Commitments: Total 2003 2004 2005 2006 2007 Thereafter
----------------------- ------ ------ ---- ---- ---- ---- ----------
Line of Credit.............. $ -- $ -- $ -- $ -- $ -- $ -- $--
Other Commercial Commitments 4,333 3,445 399 190 157 142 --
------ ------ ---- ---- ---- ---- ---
Total Commercial Commitments $4,333 $3,445 $399 $190 $157 $142 $--
====== ====== ==== ==== ==== ==== ===
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 and abandon reserves, using the units of
production method based upon the ratio of current production to total proved
reserves. Depletion is a significant component of our net income.
Proportionally, it represented over 40% of our total revenues in the year 2002
and approximately 30% of total revenues in the years 2001 and 2000. Any
reduction in proved reserves without a corresponding reduction in capitalized
costs will increase the depletion rate.
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 reservoir engineers. These reserve estimates are
inherently imprecise as they 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.
Different reserve engineers may make different estimates of reserves based on
the same data. 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 reservoir 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, the impairment of oil and gas properties is not reversible at a later
date even if oil and gas prices increase. We recorded a ceiling impairment of
$20.8 million, pre-tax, in 2001, but will not require an impairment for the
year 2002.
30
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.
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. At December 31, 2002, they represented
a $6.9 million current liability and a $359,000 long-term liability.
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 of our hedges, which could represent either gains or losses,
would be reported when calculated as an adjustment of interest and other income.
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. In the past we have chosen to obtain the fair
value of commodity derivatives from the counter parties to those contracts.
Since the counter parties are market makers, they were able to provide us with
a literal market value, or what they would be willing to settle such contracts
for as of the given date. We currently use a software product from an outside
vendor to calculate the fair value of our hedges. This vendor provides the
necessary NYMEX futures prices and the calculated volatility in those prices to
us daily. The software is programmed to apply a consistent discounted cash flow
technique, using these variables and a discount rate derived from prevailing
interest rates. This software is successfully used by several of our peers. Its
methods are in compliance with the requirements of SFAS No. 133 and have been
reviewed by a national accounting firm.
Our existing commodity hedges are perfectly effective. Should circumstances
change, all or part of the hedges could become ineffective. We would be
required to record an income impact at that time. For example, should we fail
to produce oil and gas in amounts adequate to cover the hedges, the derivative
would immediately be considered speculative and its entire change in value
would be recorded as either a gain or loss in interest and other income.
Thereafter, the derivative would be marked to market each quarter,
substantially increasing the volatility of our earnings.
31
Business Combinations and Goodwill
Recent accounting pronouncements prescribe that all future acquisitions will
be accounted for using the purchase method. Under the purchase method, the
acquiring company adds to its balance sheet the estimated fair values of the
acquired company's assets and liabilities. Any excess of the purchase price
over the fair values of the tangible and intangible net assets acquired is
recorded as goodwill. Also under recent accounting pronouncements, goodwill
with an indefinite useful life is no longer amortized, but instead is assessed
for impairment at least annually.
Corporate acquisitions, or mergers, have contributed significantly to
Mission's growth. The merger with Bargo in 2001 was the most significant. We
consider similar transactions to be a viable way to continue Mission's growth.
Application of the purchase method of accounting requires us to estimate the
fair value of every asset and liability, both tangible and intangible, which
are acquired in a merger or corporate acquisition. We make various assumptions
and estimates in arriving at those fair values. For example, current assets and
liabilities are assumed to be at fair value. The most significant assets to be
valued are the proved oil and gas properties. This valuation requires an
estimate of proved reserves and future net revenues. We hire independent
reservoir engineers to provide the estimated volume of proved reserves. The
difficulties and risk of inaccuracies associated with these estimated proved
reserves have been described earlier in this section under 'Full Cost Method of
Accounting for Oil and Gas Assets" and in the "Risk Factors" section.
Where the full cost ceiling test requires the use of end of period prices to
calculate future net revenues, we are allowed to select prices that we feel are
more likely to be realized when attempting to value the reserves of an
acquisition candidate. We could use flat, escalating or variable future prices
in the valuation. In order to make the fair value assessment as objective as
possible, we typically use future price forecasts, such as the NYMEX futures,
adjusted to the wellhead by known price differentials, that are posted and
accessible to the public. These prices are applied to the estimated proved
reserves to arrive at estimates of future net revenues. Future net revenues are
then discounted at the rate we feel is appropriate, generally our required rate
of return on projects or an industry standard given existing market conditions,
to arrive at the estimated fair value of proved reserves.
We apply these same general principles in arriving at the fair value of
unproved reserves acquired in a business combination. These unproved reserves
are generally classified as either probable or possible reserves. Independent
reservoir engineers may provide estimates of probable and possible reserves.
Because of their very nature, probable and possible reserve estimates are more
imprecise than those of proved reserves. To compensate for the inherent risk of
estimating and valuing unproved properties, we reduce the discounted future net
revenues of probable and possible reserves by what we consider to be an
appropriate risk-weighting factor for each particular instance. The probable or
possible reserves are reviewed on an individual field basis to determine the
appropriate risk-weighting factor for each field. The risk-weighting factor can
therefore differ substantially by field, depending upon the determinations of
our engineers and geologists.
Our 2001 merger with Bargo created goodwill. The annual test for goodwill
impairment requires some of the same valuation steps, and therefore the same
types of estimates and management judgment, as the valuation of an acquired
company. Mission designated December 31st as the date for its annual test.
Based upon such test for 2002, goodwill should be fully impaired. The valuation
was based on the following procedures and information:
. compute a cash flow model of Mission's oil and gas assets using third
party information and verification;
. apply risking parameters to the various categories of oil and gas
reserves using reputable third party sources for risk profile;
. apply a discount rate to such valuation that approximates Mission's cost
of capital and cost of debt;
. reduce this valuation by Mission's net debt to ascertain the equity fair
value; and
. compare book equity to fair value equity.
32
This calculation resulted in an equity fair value below book equity plus
goodwill. This means that the entire amount of goodwill is impaired. If
goodwill is created through any future merger or corporate acquisition, the
annual impairment test of goodwill would be similar.
Revenue Recognition
Mission records revenues from sales of crude oil and natural gas when
delivery to the customer has occurred and title has transferred. This occurs
when production has been delivered to a pipeline or a tanker lifting has
occurred. We may share ownership with other producers in certain properties. In
this case, we use the sales method to account for sales of production. It is
customary in the industry for various working interest partners to sell more or
less than their entitled share of natural gas production, creating gas
imbalances. Under the sales method, gas sales are recorded when revenue checks
are received or are receivable on the accrual basis. Typically no provision is
made on the balance sheet to account for potential amounts due to or from
Mission related to gas imbalances. If the gas reserves attributable to a
property have depleted to the point that there are insufficient reserves to
satisfy existing imbalance positions, a liability or a receivable, as
appropriate, should be recorded equal to the net value of the imbalance. As of
December 31, 2002, we have recorded a net liability of approximately $454,000
representing approximately 266,000 MCF at an average price of $1.71 per MCF,
related to imbalances on properties at or nearing depletion. We value gas
imbalances using the price at which the imbalance originated if stated in the
gas balancing agreement or we use the current price where there is no gas
balancing agreement available. Reserve reductions 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.
Asset Retirement, Impairment or Disposal
We are adopting SFAS No. 143, "Accounting for Asset Retirement Obligations"
effective January 1, 2003. Currently our estimate of future plugging and
abandonment and dismantlement costs is charged to income by being included in
the capitalized costs that we deplete 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 must estimate asset retirement costs for all of our assets
as of today, inflation adjust today's costs to the forecast abandonment date,
discount that amount back to the date we acquired the asset and record an asset
retirement liability in that amount with a corresponding addition to our asset
value. Then we must compute all depletion previously taken on future plugging
and abandonment costs, and reverse that depletion. Finally, we must accrete the
liability to present day. Any income effect of this initial implementation will
be reflected as a change in accounting method on our statement of operations.
After initial implementation, we will reduce the liability as abandonment costs
are incurred. Should actual costs differ from the estimate, the difference will
be reflected as an abandonment gain or loss in the statement of operations when
the abandonment occurs. We are also developing a process through which to track
and monitor the obligations for each asset.
As with previously discussed estimates, the estimation of our asset
retirement obligation is dependent upon many variables. We attempt to limit
impact of management's subjective judgment on these variables by using the
input of qualified third parties when possible. We engaged an independent
engineering firm to evaluate our properties and to provide us with estimates of
abandonment costs. We used the remaining estimated useful life from the
year-end Netherland, Sewell & Associates, Inc. reserve report in estimating
when abandonment could be expected. 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.
33
Results of Operations
The table below presents the major components of financial and operating
performance to be discussed (amounts in thousands, except average prices and
per BOE measures):
Year Ended December 31,
----------------------------
2002 2001(1) 2000
-------- -------- --------
Oil and gas revenues--US............................................... $112,879 $131,358 $107,938
Oil revenues--Ecuador.................................................. -- 1,877 4,315
Gas plant revenues..................................................... -- 4,456 6,070
Interest and other income (expense).................................... (7,415) 4,386 957
-------- -------- --------
Total revenue................................................... 105,464 142,077 119,280
Lease operating expense--US............................................ 43,222 41,702 21,738
Lease operating expense--Ecuador....................................... -- 3,071 2,815
Taxes other than income................................................ 9,246 6,656 6,273
Transportation costs................................................... 834 73 270
Gas plant expenses..................................................... -- 2,118 2,677
Depreciation, depletion and amortization--US........................... 43,291 44,602 31,909
Depreciation, depletion and amortization--Ecuador...................... -- 504 745
Impairment expense..................................................... 16,679 27,971 --
Disposition of hedges.................................................. -- -- 8,671
Uncollectible gas revenues............................................. -- 2,189 --
Loss on sale of assets................................................. 2,645 11,600 --
General and administrative expenses.................................... 12,758 15,160 8,821
Interest expense....................................................... 26,853 23,664 15,375
Income tax benefit..................................................... (11,580) (9,055) (12,222)
-------- -------- --------
Net income (loss) before cumulative effect of changes in accounting
method............................................................... (38,484) (28,178) 32,208
======== ======== ========
Cumulative effect of a change in accounting method, net of deferred tax -- 2,767 --
======== ======== ========
Net income (loss)...................................................... $(38,484) $(30,945) $ 32,208
======== ======== ========
Production
Oil and condensate (MBBLS)--US...................................... 3,423 3,303 2,206
Oil and condensate (MBBLS)--Ecuador................................. -- 95 174
Natural gas (MMCF).................................................. 12,524 17,597 20,478
Oil equivalent (MBOE)............................................... 5,510 6,331 5,793
Average sales price, including the effect of hedges
Oil and condensate (per BBL)--US.................................... $ 21.37 $ 22.30 $ 20.53
Oil and condensate (per BBL)--Ecuador............................... $ -- $ 19.76 $ 24.80
Natural gas (per MCF)............................................... $ 3.17 $ 3.28 $ 3.06
Average sales price, excluding the effect of hedges
Oil and condensate (per BBL)--US.................................... $ 21.84 $ 21.81 $ 24.40
Oil and condensate (per BBL)--Ecuador............................... $ -- $ 19.76 $ 24.80
Natural gas (per MCF)............................................... $ 3.07 $ 4.13 $ 3.84
Average lease operating expense per BOE--US............................ $ 7.84 $ 6.69 $ 3.87
Average lease operating expense per BOE--Ecuador....................... $ -- $ 32.33 $ 16.18
Average G&A expenses per BOE........................................... $ 2.32 $ 2.39 $ 1.52
Average depletion rate per BOE--US..................................... $ 7.74 $ 6.72 $ 5.46
Average depletion rate per BOE--Ecuador................................ $ -- $ 5.31 $ 4.28
- --------
(1) Operations of properties acquired from Bargo began May 16, 2001 and Ecuador
operations ceased June 2001.
34
Operations of the gas plants are summarized as follows:
Year Ended December 31,
-----------------------
2002 2001(1) 2000
---- ------- ------
Plant product sales volume (MBBLS).... -- 203 257
Average product sales price per barrel -- $18.15 $20.31
- --------
(1) The Snyder gas plant was sold in October 2001 and the Diamond M gas plant
was sold in November 2001.
Year Ended 2002 Compared to Year Ended 2001
Net Income--Net loss for the year ended December 31, 2002 was $38.5 million,
or $1.63 per share on a diluted basis, while net loss for the year ended
December 31, 2001 was $30.9 million, or $1.54 per share on a diluted basis.
Oil and Gas Revenues--Oil and gas revenues, were $112.9 million in the year
ended December 31, 2002, compared to $133.2 million for the respective period
in 2001. This represents a 15.2% decrease in revenues.
Oil Revenues--Oil revenues decreased slightly to $73.2 million for the
year 2002 from $75.5 million for the year 2001. The absence of revenues from
Ecuadorian oil accounts for the majority of the decrease in oil revenues. We
sold our interests in the Ecuador fields in June 2001.
Gas Revenues--Gas revenues decreased 31.1% from $57.7 million in 2001 to
$39.7 million in 2002. Average realized gas prices, including hedge impact,
were down $0.11 from $3.28 per MCF in the year ended December 31, 2001. Gas
production declined 28.8% compared to the previous year with 12,524 MMCF and
17,597 MMCF in the years 2002 and 2001, respectively. The production decline
was expected and is primarily related to our sale of additional properties
throughout the year, downtime offshore and along the Gulf coast during
September and October 2002 when hurricanes passed through, and the
consistent production decline of our offshore properties.
Hedges--The realized prices discussed above include the impact of oil and
gas hedges. A decrease of $342,000 related to hedge activity was reflected
in oil and gas revenues for the year 2002, while a decrease in oil and gas
revenues of $13.4 million was reflected for the previous year. Ecuadorian
oil production in 2001 was not hedged.
Interest and Other Income--Interest and other income decreased $11.8 million
from a net gain of $4.4 million reported for the year 2001 to a net loss of
$7.4 million reported for the year 2002. A $9.0 million loss from hedge
ineffectiveness, as computed under the requirements of SFAS. No. 133, was
recorded in this line item for the year 2002. A net gain from hedge
ineffectiveness of $4.8 million was recorded in 2001. A $1.7 million gain
resulting from the settlement of the royalty calculation dispute with the MMS
was also recorded in 2002.
Lease Operating Expenses--Total lease operating expenses for the year 2002
were $43.2 million compared to $44.8 million in the year 2001, a decrease of
$1.6 million. Ecuadorian operations, which were sold in June 2001, accounted
for $3.1 million in the year 2001. On a barrel equivalency basis, domestic
lease operating expenses were $7.84 per BOE in 2002 and $6.69 per BOE in 2001.
Costs for the properties acquired in the 2001 merger with Bargo and the June
2001 South Louisiana acquisition were included in lease operating expenses for
the full year. Many of these properties are higher fixed costs properties. Our
production declines in other areas have contributed to the increased operating
expenses on a BOE basis.
Taxes Other Than Income--Production taxes, ad valorem taxes and franchise
taxes are included in this amount. Production taxes are calculated as a
percentage of revenue in many areas; therefore, they vary with both price and
production levels. Ad valorem taxes are assessed based upon property value each
year. The most
35
significant contribution to increased ad valorem taxes is the 2001 merger with
Bargo and the acquisition of South Louisiana properties in 2001 because a full
year's ad valorem taxes was recognized on those properties in 2002.
Transportation Costs--Transportation costs represent those expenses incurred
to bring production to sale points such as pipeline fees and gas gathering
fees. In 2002, we were responsible for paying transportation for more of our
oil and gas sales. In 2001, the purchaser, Torch, assumed responsibility for
transportation costs on the gas it purchased from us.
Depreciation, Depletion and Amortization--Depreciation, depletion and
amortization ("DD&A") of domestic properties decreased 2.9% from $44.6 million
in 2001 to $43.3 million in 2002. On a per BOE basis, DD&A increased 15.2%,
from $6.72 in 2001 to $7.74 in 2002, reflecting decreases in reserves as a
result of property sales and revisions. Depletion of the Ecuadorian full cost
pool for 2001 was $504,000. The Ecuadorian properties were sold in June 2001.
Impairment Expense--The impairment expense in 2002 of $16.7 million is the
result of the impairment of goodwill. The impairment expense reported in 2001
consists of a $20.8 million full cost ceiling impairment, the write-off of a
$6.2 million long-term receivable and a $914,000 charge for exploration stage
mining activities. Both the goodwill and the full cost ceiling impairment are
discussed in detail under "Critical Accounting Policies". The long-term
receivable represented a production payment due from a foreign energy company.
Management determined that the receivable was uncollectible in the fourth
quarter of 2001.
Loss on Sale of Assets--The loss on sale of assets of $2.6 million in 2002
is primarily attributable to the post-closing settlement on the sale of our
Ecuadorian interests.
General and Administrative Expenses--General and administrative expenses
totaled $12.7 million in the year ended December 31, 2002 as compared to $15.2
million in the year ended December 31, 2001, for a decrease of 16.4%. Severance
costs were $3.7 million in 2002 compared with $2.5 million of severance and
outsourcing contract termination fees in 2001. Additionally, salaries and
benefits were $3.1 million lower in 2002 than in 2001, as a result of staff
reductions in early 2002. The termination of outsourcing contracts reduced
management fees by $1.6 million in 2002.
Income Taxes--The benefit for federal and state income taxes for the year
ended December 31, 2002 was based upon a 35% effective tax rate. The $4.3
million valuation allowance on deferred taxes applicable at December 31, 2001
has been increased to $5.3 million at December 31, 2002, because we have
determined that the portion of deferred tax asset relating to state tax losses
generated during the period would not be realized. In assessing the
realizability of the deferred tax assets, management considers whether it is
more likely than not that some portion or all of the deferred tax assets will
not be realized. The ultimate realization of deferred tax assets is dependent
upon the generation of future taxable income during the periods in which those
temporary differences become deductible. Based upon the projection for future
state taxable income, management believes it is more likely than not that we
will not realize its deferred tax asset related to state income taxes.
Interest Expense--Interest expense increased 13.5% to $26.9 million for the
year ended December 31, 2002 from $23.7 million in the year ended December 31,
2001. Approximately $5.7 million of the increase is related to the additional 5
months that the $125 million of 10 7/8% senior subordinated notes were
outstanding and accruing interest during 2002. The increase is partially offset
by the change in the fair value of Mission's interest rate swap, reported as a
reduction of interest expense in both years. The net gain from the change in
fair value was $2.2 million in 2002 and $332,000 in 2001.
Year Ended 2001 Compared to Year Ended 2000
Net Income--Net loss for the year ended December 31, 2001 was $30.9 million,
or $1.54 per share on a diluted basis, while net income for the year ended
December 31, 2000 was $32.2 million, or $2.27 per share on a diluted basis.
36
Oil and Gas Revenues--Oil and gas revenues, were $133.2 million in the year
ended December 31, 2001, compared to $112.3 million for the respective period
in 2000. This represents a 18.6% increase.
Oil Revenues--Total oil revenues increased to $75.5 million for the year
2001 from $49.6 million for the year 2000. Domestic oil revenues benefited
from a 9% increase in realized oil prices from $20.53 in 2000 to $22.30 in
2001 and a 50% increase in domestic oil production from 2.2 MMBBLS in 2000
to 3.3 MMBBLS in 2001. The improved domestic oil production was directly
related to acquisitions made in 2001, particularly the Raccoon Bend, Wasson,
Levelland and East Texas fields acquired in the Bargo merger.
A decrease in Ecuadorian oil revenues of 57% occurred because the fields
were sold at mid-year and realized oil prices declined. Ecuadorian oil
production was 95,000 barrels, sold at $19.76, for the year 2001 compared to
174,000 barrels, sold at $24.80 for the year 2000.
Gas Revenues--Gas revenues decreased 9% from $62.7 million in 2000 to
$57.7 million in 2001. Average realized gas prices, including hedge impact,
increased 7% from $3.06 per MCF in the year ended December 31, 2000 to $3.28
per MCF in the year ended December 31, 2001. Gas production declined 14%
compared to the previous year with 17,597 MMCF and 20,478 MMCF in the years
2001 and 2000, respectively. This decline reflected the effects of the sale
of short-life gas properties in 2000.
Hedges--The realized prices discussed above include the impact of oil and
gas hedges. A decrease of $13.4 million related to hedge activity was
reflected in oil and gas revenues for the year 2001, while a decrease in oil
and gas revenues of $24.5 million was reflected for the previous year.
Ecuadorian oil production was not hedged.
Gas Plant Revenues--Gas plant revenues were $4.5 million in 2001 compared to
$6.1 million in 2000. Contributing to this decrease was an 11% decline in
average realized plant liquid prices. Also, only 10 months of Snyder gas plant
operations and 11 months of Diamond M gas plant operations were reported in
2001 because the plants were sold during the year.
Interest and Other Income--Interest and other income increased from $957,000
reported for the year 2000 to $4.4 million reported for the year 2001. The
primary reason for this increase is the inclusion of non-cash hedge
ineffectiveness, as computed under the requirements of SFAS. No. 133, in this
line item. A net gain from hedge ineffectiveness of $4.8 million was recorded
in 2001. Two legal settlements totaling $290,000 and the write-off of $0.9
million of various receivables in 2001 partially offset the favorable impact of
hedge ineffectiveness in 2001. There were no legal settlements in 2000 and
$135,000 of receivables were written off in 2000.
Lease Operating Expenses--Total lease operating expenses for the year 2001
were $44.8 million compared to $24.6 million in the year 2000. On a barrel
equivalency basis, domestic lease operating expenses were $6.69 per BOE in 2001
and $3.87 per BOE in 2000, increasing 92.2% from $21.7 million in 2000 to $41.7
million in 2001. As a result of the Bargo merger and the south Louisiana
property acquisition, there are more wells to operate and many are oil wells
that tend to be higher cost. Additionally, third-party oilfield service costs
rose in response to record commodity prices at the beginning of 2001. After the
Bargo merger, we reviewed our properties for cost saving opportunities. Some of
these opportunities required initial spending in the form of workovers or
acceleration of maintenance and repair projects in order for future operations
to benefit. Ecuadorian operations, which were sold in June 2001, accounted for
$2.8 million of total lease operating expenses in the year 2000 and $3.1
million in the year 2001.
Taxes Other Than Income--Production taxes, ad valorem taxes and franchise
taxes are included in this amount. Production taxes are calculated as a
percentage of revenue in many areas; therefore, they vary with both price and
production levels. While production taxes increased on an absolute basis, they
remained essentially the same on a per BOE basis in both years. Ad valorem
taxes are assessed based upon property value each year. The most significant
contribution to increased taxes is the acquisition of properties; however only
one-half year of additional ad valorem taxes was included in 2001 for the
acquired properties because they were acquired at mid-year.
37
Gas Plant Expenses--Gas plant expenses decreased 22% from $2.7 million in
2000 to $2.1 million in the year 2001. The decrease was related to the
reduction in gas purchase costs. Also, only 10 months of Snyder gas plant
operations and 11 months of Diamond M gas plant operations were reported in
2001 because the plants were sold within the year.
Transportation Costs--Transportation costs represent those expenses incurred
to bring production to sale points such as pipeline fees and gas gathering
fees. The increase in 2001 was primarily attributable to the properties
acquired in the Bargo merger, including Raccoon Bend.
Depreciation, Depletion and Amortization--DD&A of domestic properties
increased 40% from $31.9 million in 2000 to $44.6 million in 2001. On a per BOE
basis, DD&A increased 23%, from $5.46 in 2000 to $6.72 in 2001, reflecting
increased future development costs associated with new reserves. Depletion of
the Ecuadorian full cost pool for 2000 was $745,000 compared to $504,000 in
2001. The Ecuadorian properties were sold in June 2001.
Impairment Expense--The impairment expense reported in 2001 consists of a
$20.8 million full cost ceiling impairment, the write off a $6.2 million
long-term receivable, and a $914,000 charge for exploratory stage mining
activities. The full cost ceiling impairment is discussed in detail under
"Critical Accounting Policies: Full Cost Method of Accounting for Oil and Gas
Assets." The long-term receivable represented a production payment due from a
foreign energy company. Management determined that the receivable was
uncollectible in the fourth quarter of 2001.
Uncollectible Gas Revenues--Mission wrote off as uncollectible a $2.2
million receivable from a subsidiary of Enron Corp. as a result of the
bankruptcy filing of Enron.
Loss on Sale of Assets--The loss on sale of assets consists of a $12.7
million loss on the sale of our Ecuadorian interests, which was offset by a
$1.1 million gain on the sale of the Snyder and Diamond M gas plants.
General and Administrative Expenses--General and administrative expenses
totaled $15.1 million in the year ended December 31, 2001 as compared to $8.8
million in the year ended December 31, 2000, for an increase of 72%. Salaries
and benefits increased $2.8 million in 2001 over 2000 levels as a result of our
increased employee count after the Bargo merger. Also the costs of steps to
reduce future costs, including one-time charge of $1.9 million related to staff
reductions and $620,000 related to the termination of outsourcing contracts,
contributed to the increase.
Income Taxes--At December 31, 2000, we determined that it was more likely
than not that the deferred tax assets would be realized based on current
projections of taxable income due to higher commodity prices at year end 2000,
and the valuation allowance was decreased by $19.8 million to zero. At December
31, 2001, however, we determined that a portion of the deferred tax assets
would not be realized. In assessing the realizability of the deferred tax
assets, management considers whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The ultimate
realization of deferred tax assets is dependent upon the generation of future
taxable income during the periods in which those temporary differences become
deductible. Based upon the projections for future state taxable income,
management believes it is more likely than not that we will not realize the
deferred tax asset related to state income taxes. Based upon the projections of
future taxable income, management believes it is more likely than not that we
will not realize our deferred tax asset related to the impairment of the
production payment, as the reversal of the deferred tax asset will result in a
capital loss for federal income tax purposes, and we do not project any
transactions resulting in capital gains to offset the capital loss. Therefore,
the valuation allowance was increased by $4.3 million for the year ending
December 31, 2001.
Interest Expense--Interest expense increased 54% to $23.7 million for the
year ended December 31, 2001 from $15.4 million in the year ended December 31,
2000. Increased borrowings under the credit facility in 2001
38
due to the Bargo merger and the additional $125.0 million of senior
subordinated notes issued in May 2001 contributed to the expense increase.
Additionally, a net gain from the change in fair value of Mission's interest
rate swap was reported as a reduction of 2001 interest expense.
Cumulative Effect of Change in Accounting Method--The adoption of SFAS No.
133 at January 1, 2001 resulted in the recognition of a non-cash $2.8 million
loss, net of taxes, representing the cumulative effect of a change in
accounting method related to an interest rate swap that did not qualify for
hedge accounting treatment.
Other Matters
Dividends
At present, there is no plan to pay dividends on the common stock. Certain
restrictions contained in Mission's outstanding notes and credit facility limit
the amount of dividends that may be declared.
New Accounting Pronouncements
In July 2001, FASB issued Statement No. 143. SFAS No. 143, Accounting for
Asset Retirement Obligations, provided accounting requirements for retirement
obligations associated with tangible long-lived assets, including:
. the timing of liability recognition;
. initial measurement of the liability;
. allocation of asset retirement cost to expense;
. subsequent measurement of the liability; and
. financial statement disclosures.
Statement No. 143 requires that we record a liability for the fair value of
our 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 obligation is added to the carrying amount of the oil and gas
properties and this additional carrying amount is depreciated over the life of
the properties. If the obligation is settled for other than the carrying amount
of the liability, we will recognize a gain or loss on settlement.
We are required and plan to adopt the provisions of Statement No. 143 for
the quarter ending March 31, 2003. Our calculations are nearing completion. We
expect to record an asset retirement liability of between $40.0 million and
$50.0 million and a loss from a change in accounting method of between $1.0 and
$5.0 million in the quarter ended March 31, 2003.
SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statements No. 13 and Technical Corrections, was issued in April 2002.
SFAS No. 145 amends existing guidance on reporting gains and losses on the
extinguishments of debt to prohibit the classification of the gain or loss as
extraordinary, as the use of such extinguishments have become part of the risk
management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to
require sale-leaseback accounting for certain lease modifications that have
economic effects similar to sale-leaseback transaction. The provision of the
Statement related to the rescission of Statement No. 4 is applied in fiscal
years beginning after May 15, 2002. Earlier application of these provisions is
encouraged. The provisions of Statement related to Statement No. 13 were
effective for transactions occurring after May 15, 2002, with early application
encouraged. The adoption of SFAS No. 145 does not currently effect our
financial statements, however, its provisions could impact the treatment of
future transactions.
39
SFAS No. 146, Accounting for Exit or Disposal Activities, was issued in June
2002. SFAS No. 146 addresses significant issues regarding the recognition,
measurement, and reporting of costs that are associated with exit and disposal
activities, including restructuring activities that are currently accounted for
pursuant to the guidance set forth in EITF Issue No. 94-3, Liability
Recognition of Certain Employee Termination Benefits and Other Costs to Exit an
Activity. SFAS No. 146 is effective for the exit and disposal activities
initiated after December 31, 2002. The Company will apply SFAS No. 146 as
appropriate to future activities.
In November 2002, FASB issued Interpretation No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107
and a rescission of FASB Interpretation No. 34. This interpretation elaborates
on the disclosures to be made by a guarantor in its interim and annual
financial statements about its obligations under guarantees issued. The
interpretation also clarifies that a guarantor is required to recognize, at
inception of a guarantee, a liability for the fair value of the obligation
undertaken. The initial recognition and measurement provisions of the
interpretation are applicable to guarantees issued or modified after December
31, 2002 and are not expected to materially effect our financial statements.
The disclosure requirements are effective for financial statements of interim
and annual periods ending after December 15, 2002.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation--Transition and Disclosure, an amendment of SFAS No. 123, that
provides alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements. Some of
the disclosure modifications are required for fiscal years ending after
December 15, 2002 and are included in the "Notes to Consolidated Financial
Statements".
FASB issued Interpretation No. 46, Consolidation of Variable Interest
Entities, an interpretation of APB No. 51, in January 2003. This interpretation
addresses the consolidation by business enterprises of variable interest
entities as defined in the interpretation. The interpretation applies
immediately to variable interest entities created after January 31, 2003, and
to variable interests in variable interest entities obtained after January 31,
2003. We do not own an interest in any variable interest entities; therefore,
this interpretation is not expected to have a material effect on our financial
statements.
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. Recent oil hedges placed in periods of high oil prices were
swaps that fix the price to be received.
Our realized price for natural gas per MCF is generally $0.11 less than the
NYMEX MMBTU price. Our realized price for oil is generally $0.95 per BBL less
than NYMEX. Realized prices differ from NYMEX due to factors such as the
location of the property, the heating content of natural gas and the quality of
oil. The oil differential excludes the impact of Point Pedernales field
production for which our selling price is capped at $9.00 per BBL. The Point
Pedernales field was sold in March 2003 to the operator.
40
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, 2002 prices, our
cash flows would decrease by $12.7 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 10, 2003.
NYMEX NYMEX
BBLS Price Price
Per Total Floor/Swap Ceiling
Oil Hedges Day BBLS Type Avg. Avg.
---------- ----- ------- ---- ---------- -------
First Qtr. 2003. 4,000 360,000 Swap $24.82 n/a
Second Qtr. 2003 4,000 364,000 Swap $24.31 n/a
Third Qtr. 2003. 3,500 322,000 Swap $23.95 n/a
Fourth Qtr. 2003 3,500 322,000 Swap $23.59 n/a
NYMEX NYMEX
Price Price
MMBTU Total Floor Ceiling
Gas Hedges Per Day MMBTU Type Avg. Avg.
---------- ------- --------- ------ ----- -------
First Qtr. 2003. 15,000 1,370,000 Collar $3.24 $4.64
Second Qtr. 2003 15,000 1,365,000 Collar $3.18 $4.02
Third Qtr. 2003. 15,000 1,380,000 Collar $3.19 $4.10
Fourth Qtr. 2003 15,000 1,380,000 Collar $3.24 $4.54
First Qtr. 2004. 8,000 728,000 Collar $4.13 $5.39
Second Qtr. 2004 5,000 455,000 Collar $3.70 $4.08
Third Qtr. 2004. 5,000 460,000 Collar $3.70 $4.04
Fourth Qtr. 2004 5,000 460,000 Collar $3.85 $4.23
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
We may also enter into financial instruments such as interest rate swaps to
manage the impact of interest rates. Effective September 22, 1998, we 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. This agreement did not qualify for
hedge accounting. It was marked to market each quarter. At December 31, 2002,
the fair value was reported as a $1.8 million liability on the balance sheet.
In February 2003, we cancelled this swap by paying the counter party
approximately $1.3 million, the fair value of the swap on the cancellation
date. The low market value compared favorably to our $4.8 million maximum
possible exposure under the terms of the swap effective at the cancellation
date. In addition, we believe that our earnings volatility will be reduced as a
result of the cancellation.
41
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page
Number
------
Independent Auditors' Report................................................................. 43
Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001.............................. 44
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and
2000.................................................................................... 46
Consolidated Statements of Changes in Stockholders' Equity and Comprehensive Loss for the
Years Ended December 31, 2002, 2001 and 2000............................................ 47
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and
2000.................................................................................... 48
Notes to Consolidated Financial Statements................................................ 50
42
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders of
Mission Resources Corporation and Subsidiaries:
We have audited the accompanying consolidated balance sheets of Mission
Resources Corporation (formerly Bellwether Exploration Company) and
subsidiaries as of December 31, 2002 and 2001 and the related consolidated
statements of operations, changes in stockholders' equity and comprehensive
loss, and cash flows for each of the years in the three-year period ended
December 31, 2002. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mission
Resources Corporation and subsidiaries as of December 31, 2002 and 2001 and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2002 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2002, the Company adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 142, "Goodwill and other Intangible Assets." As
discussed in Note 2 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities in 2001.
KPMG LLP
Houston, Texas
March 14, 2003
43
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, December 31,
2002 2001
ASSETS ------------ ------------
(Amounts in thousands)
CURRENT ASSETS:
Cash and cash equivalents............................................. $ 11,347 $ 603
Accounts receivable and accrued revenues.............................. 18,931 25,668
Current portion of interest rate swap................................. -- 180
Commodity derivative asset............................................ -- 8,359
Prepaid expenses and other............................................ 2,148 3,879
--------- ---------
Total current assets............................................... 32,426 38,689
--------- ---------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties (full cost)
United States--Unproved properties of $8,369 and $15,530 excluded from
amortization as of December 31, 2002 and 2001, respectively......... 775,344 753,905
Accumulated depreciation, depletion and amortization.................. (474,625) (374,167)
--------- ---------
Net property, plant and equipment.................................. 300,719 379,738
Leasehold, furniture and equipment.................................... 3,545 3,347
Accumulated depreciation.............................................. (1,449) (916)
--------- ---------
Net leasehold, furniture and equipment............................. 2,096 2,431
--------- ---------
LONG TERM RECEIVABLE.................................................. -- 899
GOODWILL & OTHER INTANGIBLES.......................................... -- 15,436
OTHER ASSETS.......................................................... 7,163 10,571
--------- ---------
$ 342,404 $ 447,764
========= =========
See Notes to Consolidated Financial Statements.
44
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, December 31,
2002 2001
LIABILITIES AND STOCKHOLDERS' EQUITY ------------ ------------
(Amounts in thousands,
except share information)
CURRENT LIABILITIES:
Accounts payable and accrued liabilities..................................... $ 24,498 $ 38,584
Commodity derivative liabilities............................................. 6,973 --
Current portion of interest rate swap........................................ 3 --
-------- --------
Total current liabilities................................................. 31,474 38,584
-------- --------
LONG-TERM DEBT
Revolving credit facility.................................................... -- 35,000
Subordinated notes due 2007.................................................. 225,000 225,000
Unamortized premium on issuance of $125 million subordinated notes........... 1,431 1,695
-------- --------
Total long-term debt...................................................... 226,431 261,695
COMMODITY DERIVATIVE LIABILITIES, excluding current portion.................. 359 --
INTEREST RATE SWAP, excluding current portion................................ 1,817 4,248
DEFERRED INCOME TAXES........................................................ 16,946 31,177
OTHER LIABILITIES............................................................ -- 1,820
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 5,000,000 shares authorized; none issued or
outstanding at December 31, 2002 and 2001.................................. -- --
Common stock, $0.01 par value, 60,000,000 shares authorized, 23,896,959 and
14,259,626 shares issued at December 31, 2002 and December 31, 2001,
respectively............................................................... 239 239
Additional paid-in capital................................................... 163,837 163,735
Retained deficit............................................................. (92,599) (54,115)
Treasury stock, at cost, 311,000 shares...................................... (1,905) (1,905)
Other comprehensive income, net of taxes..................................... (4,195) 2,286
-------- --------
Total stockholders' equity................................................ 65,377 110,240
-------- --------
$342,404 $447,764
======== ========
See Notes to Consolidated Financial Statements.
45
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
(Amounts in thousands, except per share data)
REVENUES:
Gas revenues................................................. $ 39,715 $ 57,705 $ 62,652
Oil revenues--United States.................................. 73,164 73,653 45,286
Oil revenues--Ecuador........................................ -- 1,877 4,315
Gas plant revenues........................................... -- 4,456 6,070
Interest and other income (expense).......................... (7,415) 4,386 957
-------- -------- --------
105,464 142,077 119,280
-------- -------- --------
COSTS AND EXPENSES:
Lease operating expenses--United States...................... 43,222 41,702 21,738
Lease operating expenses-- Ecuador........................... -- 3,071 2,815
Taxes other than income...................................... 9,246 6,656 6,273
Transportation costs......................................... 834 73 270
Gas plant expenses........................................... -- 2,118 2,677
Depreciation, depletion and amortization--United States...... 43,291 44,602 31,909
Depreciation, depletion and amortization--Ecuador............ -- 504 745
Impairment expense........................................... 16,679 27,057 --
Disposition of hedges........................................ -- -- 8,671
Uncollectible gas revenues................................... -- 2,189 --
Mining venture............................................... -- 914 --
Loss on sale of assets....................................... 2,645 11,600 --
General and administrative expenses.......................... 12,758 15,160 8,821
Interest expense............................................. 26,853 23,664 15,375
-------- -------- --------
155,528 179,310 99,294
-------- -------- --------
Income (loss) before income tax benefit and cumulative effect of
a change in accounting method................................. (50,064) (37,233) 19,986
Income tax benefit.............................................. (11,580) (9,055) (12,222)
-------- -------- --------
Income (loss) before cumulative effect of a change in accounting
method........................................................ (38,484) (28,178) 32,208
-------- -------- --------
Cumulative effect of a change in accounting method, net of tax
of $1,633..................................................... -- 2,767 --
-------- -------- --------
Net income (loss)............................................... $(38,484) $(30,945) $ 32,208
======== ======== ========
Income (loss) per share before cumulative effect of a change in
accounting method............................................. $ (1.63) $ (1.41) $ 2.32
======== ======== ========
Income (loss) per share before cumulative effect of a change in
accounting method--diluted.................................... $ (1.63) $ (1.41) $ 2.27
======== ======== ========
Net income (loss) per share..................................... $ (1.63) $ (1.54) $ 2.32
Net income (loss) per share--diluted............................ $ (1.63) $ (1.54) $ 2.27
======== ======== ========
Weighted average common shares outstanding...................... 23,586 20,051 13,899
======== ======== ========
Weighted average common shares outstanding--diluted............. 23,586 20,241 14,175
======== ======== ========
See Notes to Consolidated Financial Statements.
46
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES
IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE LOSS
(Amounts in thousands)
Preferred
Common Stock Stock Additional Other Treasury Stock
------------- ------------- Paid-In Comprehensive Retained ------------------------
Shares Amount Shares Amount Capital Income Deficit Shares Amount Total
------ ------ ------ ------ ---------- ------------- -------- ------ ------- --------
Balance December 31, 1999.......... 14,169 $142 -- $-- $ 80,455 -- $(55,378) (311) $(1,905) $ 23,314
Stock options exercised and related
tax effects....................... 91 1 -- -- 588 -- -- -- -- 589
Compensation expense--
stock options..................... -- -- -- -- 849 -- -- -- -- 849
Net income......................... -- -- -- -- -- -- 32,208 -- -- 32,208
------ ---- -- --- -------- ------- -------- ---- ------- --------
Balance December 31, 2000.......... 14,260 143 -- -- 81,892 -- (23,170) (311) (1,905) 56,960
Stock options exercised and related
tax effects....................... 177 2 -- -- 1,138 -- -- -- -- 1,140
Issuance of common stock related
to merger......................... 9,460 94 -- -- 79,906 -- -- -- -- 80,000
Compensation expense--
stock options..................... -- -- -- -- 799 -- -- -- -- 799
Comprehensive loss:
Net loss........................... -- -- -- -- -- -- (30,945) -- -- (30,945)
Hedge activity..................... -- -- -- -- -- 2,286 -- -- -- 2,286
------ ---- -- --- -------- ------- -------- ---- ------- --------
Total comprehensive loss........... (28,659)
--------
Balance December 31, 2001.......... 23,897 239 -- -- 163,735 2,286 (54,115) (311) (1,905) 110,240
Compensation expense--
stock options..................... -- -- -- -- 102 -- -- -- -- 102
Comprehensive loss:
Net loss........................... -- -- -- -- -- -- (38,484) -- -- (38,484)
Hedge activity..................... -- -- -- -- -- (6,481) -- -- -- (6,481)
------ ---- -- --- -------- ------- -------- ---- ------- --------
Total comprehensive loss........... (44,965)
--------
Balance December 31, 2002.......... 23,897 $239 -- $-- $163,837 $(4,195) $(92,599) (311) $(1,905) $ 65,377
====== ==== == === ======== ======= ======== ==== ======= ========
See Notes to Consolidated Financial Statements.
47
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
(Amounts in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................................. $(38,484) $ (30,945) $ 32,208
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization....................... 43,291 45,106 32,654
Gain on interest rate swap..................................... (2,248) (332) --
Loss (gain) due to hedge ineffectiveness....................... 9,050 (4,767) --
Mining venture................................................. -- 729 --
Cumulative effect of a change in accounting method, net of
deferred tax................................................. -- 2,767 --
Amortization of stock options.................................. 102 799 849
Amortization of deferred financing costs and bond
premium...................................................... 2,794 1,877 559
Loss on sale of assets......................................... -- 11,600 --
Disposition of hedges.......................................... -- -- 8,671
Impairment expense............................................. 16,679 27,057 --
Other.......................................................... 553 455 --
Deferred taxes................................................. (10,846) (9,650) (12,307)
Changes in assets and liabilities, net of acquisition:
Accounts receivable and accrued revenues....................... 4,364 5,669 (13,370)
Prepaid expenses and other..................................... 2,473 (3,025) 373
Accounts payable and accrued liabilities....................... (17,913) (5,611) 12,217
Due to affiliates.............................................. -- -- --
Abandonment costs.............................................. (2,593) (1,371) (1,531)
Other.......................................................... -- -- (215)
-------- --------- --------
NET CASH FLOWS PROVIDED BY OPERATING
ACTIVITIES...................................................... 7,222 40,358 60,108
-------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas properties......................... (850) (24,159) (7,078)
Acquisitions of Bargo oil and gas properties................... -- (142,028) --
Proceeds on sale of oil and gas properties, net................ 60,396 15,868 45,906
Proceeds on sale of assets, net................................ -- 15,668 --
Additions to oil and gas properties............................ (20,589) (48,040) (81,294)
Additions to gas plant facilities.............................. -- (1,047) (677)
Additions to leasehold, furniture and equipment................ (198) (527) (2,462)
Note receivable................................................ -- -- (1,281)
Other.......................................................... -- -- (446)
-------- --------- --------
NET CASH FLOWS PROVIDED BY (USED IN) INVESTING
ACTIVITIES...................................................... 38,759 (184,265) (47,332)
-------- --------- --------
See Notes to Consolidated Financial Statements.
48
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
(Amounts in thousands)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings..................................... 21,000 208,754 31,400
Net proceeds from issuance of common stock................... -- 899 496
Payments of long-term debt................................... (56,000) (199,204) (35,950)
Proceeds from issuance of senior subordinated notes due 2007,
including premium.......................................... -- 126,875 --
Credit facility costs........................................ (237) (7,278) (359)
-------- --------- --------
NET CASH FLOWS (USED IN) PROVIDED BY FINANCING
ACTIVITIES................................................. (35,237) 130,046 (4,413)
-------- --------- --------
Net increase (decrease) in cash and cash equivalents......... 10,744 (13,861) 8,363
Cash and cash equivalents at beginning of period............. 603 14,464 6,101
-------- --------- --------
Cash and cash equivalents at end of period................... $ 11,347 $ 603 $ 14,464
======== ========= ========
See Notes to Consolidated Financial Statements.
49
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
Mission Resources Corporation (the "Company") is an independent oil and gas
exploration and production company. We develop and produce crude oil and
natural gas. Mission's balanced portfolio comprises 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 is on property enhancement through exploitation and 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. A 10.11% ownership in
the East Texas Salt Water Disposal Company is accounted for using the cost
method and the $861,000 investment is included in the other assets line of the
balance sheet.
In 1999, the Company invested in a Canadian company ("Carpatsky") that had
the right to produce and sell oil and gas from two fields in the Ukraine. Due
to different business and cultural approaches, foreign regulations and
financial limitations, the Company did not have significant influence over
Carpatsky; therefore the investment in Carpatsky was reflected using the cost
method in 2000. In June 2001, the Company exchanged its interests in Carpatsky
for a production payment on Carpatsky's producing properties, reporting $6.2
million as a long-term receivable. In fourth quarter of 2001, due to increased
uncertainties in world markets and declining commodity prices and uncertainties
related to the collectibility of the receivable, it was charged to expense as
part of the impairments on the Statement of Operations.
Oil and Gas Properties
Full Cost Pool--The Company utilizes the full cost method to account for its
investment in oil and gas properties. Under this method, all costs of
acquisition, exploration and development of oil and gas reserves (including
such costs as leasehold acquisition costs, geological expenditures, dry hole
costs and tangible and intangible development costs and direct internal costs)
are capitalized as the cost of oil and gas properties when incurred. Direct
internal costs that are capitalized are primarily the salary and benefits of
geologists and engineers directly involved in acquisition, exploration and
development activities, and amounted to $1.3 million, $3.2 million and $3.3
million in the years ended December 31, 2002, 2001 and 2000, respectively.
Until June 2001, the Company had two full cost pools: United States and
Ecuador. The Company's interests in Ecuador were sold June 2001 for gross
proceeds of $8.5 million. Because the Ecuador sale involved the entire full
cost pool, the book value of the pool was removed from the Balance Sheet and
the resulting $12.7 million excess of book value over proceeds was reported as
part of the loss on sale of assets on the Statement of Operations for the year
ended December 31, 2001.
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. Costs directly associated with the acquisition and evaluation of
unproved properties are excluded from the amortization computation until it is
determined whether or not proved reserves can be assigned to the properties or
whether impairment has occurred. Depletion expense per equivalent barrel of
domestic production was approximately $7.74 in 2002, $6.72 in 2001 and $5.47 in
2000.
50
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Unproved Property Costs--The following table shows, by category of cost and
date incurred, the domestic unproved property costs excluded from amortization
(amounts in thousands):
Total at
Leasehold Exploration Development December 31,
Costs Costs Costs 2002
--------- ----------- ----------- ------------
Costs Incurred During Periods Ended:
December 31, 2002................ $1,265 $-- $302 $1,567
December 31, 2001................ 5,246 -- -- 5,246
December 31, 2000................ 328 -- -- 328
December 31, 1999................ 502 -- -- 502
Prior............................ 726 -- -- 726
------ --- ---- ------
$8,067 $-- $302 $8,369
====== === ==== ======
Such 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, 2002.
This category of costs will transfer into the full cost pool in 2003.
Included in leasehold costs are land and seismic costs incurred in the
current and prior years by the Company that are still in the evaluation stage.
Approximately $2.2 million, $1.8 million and $2.8 million were evaluated and
moved to the full cost pool in 2002, 2001 and 2000, respectively.
Sales of Properties--Dispositions of oil and gas properties held in the
domestic full cost pool are recorded as adjustments to 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 $60.4 million, $15.9 million and $46.0
million were recorded in such manner during the years 2002, 2001, and 2000,
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 ended the year 2002 at $31.17 per barrel of oil
(NYMEX WTI Cushing) and $4.74 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 elected to adjust 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 prices and the price floors 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 $11.8 million because prices prevailing at December 31, 2002
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, 2002; therefore no impairment
was required. The Company, however, recorded an oil and gas
51
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
property impairment of $20.8 million in 2001 because capitalized costs exceeded
adjusted discounted future net reserves. No such impairment to capitalized
costs was required for the year 2000.
Any reference to oil and gas reserve information in the Notes to
Consolidated Financial Statements is unaudited.
Gas Plants
On October 1, 2001 the Company sold its interest in the Snyder gas plant and
Diamond M gas plant for gross proceeds of $11.5 million and recorded a gain of
$1.1 million, which was recorded as part of sale of assets on the Statement of
Operations for the year ended December 31, 2001.
Revenue Recognition and Gas Imbalances
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. Revenues are recognized and accrued as
production occurs. In 2001 and 2000, the only customer accounting for greater
than 10% of oil and gas revenues was an affiliate of Torch Energy Advisors
("Torch"). The sales amounts were $43.3 million and $26.9 million,
respectively, and were part of domestic revenues. In 2002, no one customer
accounts for greater than 10% of oil and gas revenues.
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. Typically no provision is
made on the balance sheet to account for potential amounts due to or from
Mission related to gas imbalances. Exclusive of a liability recorded for
properties at or nearing depletion (see discussion below), the Company's
unrecorded imbalance, valued at current prices would be a $1.4 million
receivable.
When the gas reserves attributable to a property have depleted to the point
that there are insufficient reserves to satisfy existing imbalance positions, a
liability or a receivable, as appropriate, should be recorded equal to the net
value of the imbalance. As of December 31, 2002, the Company recorded a net
liability of approximately $454,000 representing approximately 266,000 MCF at
an average price of $1.71 per MCF, related to imbalances on properties at or
nearing depletion. Those 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.
Receivables
The Company uses the specific write off method of accounting for receivables
other than accruals. Joint interest billing receivables represent those amounts
due to the Company as operator of an oil and gas property by the other working
interest partners. Since these partners could also be the operator of other
properties in which the Company is a working interest partner, the
interdependency of the partners tends to assure timely payment. Past due
balances over 90 days and $30,000 are reviewed for collectibility monthly, and
charged against earnings when the potential for collection is determined to be
remote. The Company has recognized bad debt expense, included in interest and
other income on the Statement of Operations, of $185,000, $430,000 and $135,000
related to such receivables for the years ended December 31, 2002, 2001 and
2000, respectively. The Company does not have any off-balance sheet credit
exposure related to its customers.
52
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
A portion of the Company's November 2001 gas production was sold under
contract to a subsidiary of Enron Corporation ("Enron"). Payment for that
production totaling $2.2 million was due in December 2001 and was not received.
Due to Enron's bankruptcy filing and continued legal difficulties, the Company
chose to write off the entire amount due from Enron. A separate line for
uncollectible gas revenues was added to the Statement of Operations in order to
clearly segregate the $2.2 million charge to income recognized in 2001 due to
Enron's failure to make payment.
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 generations of future taxable income in periods when the temporary
differences become deductible. The effect on deferred taxes of a change in tax
rates is recognized in income in the period the change occurs.
Statements of Cash Flows
For cash flow presentation purposes, the Company considers all highly liquid
instruments purchased with an original maturity of three months or less to be
cash equivalents. Interest paid in cash for the years ended December 31, 2002,
2001 and 2000, was $26.4 million, $19.0 million and $13.8 million,
respectively. Income taxes paid in cash, net of cash refunds, for the years
ended December 31, 2001 and 2000 were $2.5 million and $109,000, respectively.
A net cash refund of approximately $1.8 million was received in the year ended
December 31, 2002.
A significant portion of the funding of the 2001 Bargo merger was non-cash:
Supplemental schedule of non-cash investing and financing activities:
Year Ended
December 31,
2001
------------
Fair value of assets and liabilities acquired:
Net current assets and other assets..................... $ 2,453
Property, plant, and equipment.......................... 260,893
Goodwill and intangibles................................ 16,601
Deferred tax liability.................................. (56,610)
--------
Total allocated purchase price.......................... $223,337
Less non-cash consideration--issuance of stock.......... $ 80,000
Less cash acquired in transaction....................... 1,309
--------
Cash used for business acquisition, net of cash acquired $142,028
========
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
53
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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, 2002, 2001 and 2000 were $96,000,
$405,000 and $312,000, respectively.
Deferred Compensation Plan
In late 1997, the Company adopted the Mission Deferred Compensation Plan.
This plan allows selected employees the option to defer a portion of their
compensation until their retirement or termination. Such deferred compensation
is invested in any one or more of six mutual funds managed by American Funds
Service Company ("Fund Manager") at the direction of the employees. The Company
designated Southwest Guaranty Trust Company as Trustee to supervise the Fund
Manager. The market value of these investments is included in current assets at
December 31, 2002, 2001 and 2000 and was approximately $419,000, $124,000 and
$25,000, respectively. An equivalent liability due to the plan participants is
included in current liabilities.
Stock-Based Employee Compensation Plans
At December 31, 2002, the Company has two stock-based employee compensation
plans, which are described more fully in Note 5. The Company accounts for those
plans under the recognition and measurement principles of APB Opinion No. 25,
Accounting or Stock Issued to Employees, and related Interpretations. No
stock-based employee compensation cost is reflected in net income for options
granted under those plans with an exercise price equal to the market value of
the underlying common stock on the date of the grant. The following table
illustrates the effect on net income and earnings per share if the Company had
applied the fair value recognition provisions of FASB Statement No. 123,
Accounting for Stock-Based Compensation, to stock-based employee compensation.
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
Net income (loss)
As reported......................... $(38,484) $(30,945) $32,208
Pro forma........................... $(39,315) $(35,007) $24,955
Earnings (loss) per share
As reported......................... $ (1.63) $ (1.54) $ 2.32
Pro forma........................... $ (1.67) $ (1.75) $ 1.80
Diluted earnings (loss) per share share
As reported......................... $ (1.63) $ (1.54) $ 2.27
Pro forma........................... $ (1.67) $ (1.75) $ 1.76
Mining Venture
During fiscal year 1992, Mission acquired an average 24.4% interest in three
mining ventures (the "Mining Venture") from an unaffiliated individual for
$128,500. At the time of such acquisition, J. P. Bryan, a member of the Mission
Board of Directors until October 2002, his brother, Shelby Bryan and Robert L.
Gerry III (the "Affiliated Group"), owned an average 21.5% interest in the
Mining Venture. Mission's interest in the Mining Venture increased as it paid
costs of the venture while the interest of the Affiliated Group decreased.
Through December 31, 2001, Mission spent an additional $185,000 primarily for
soil evaluations. These exploratory costs, plus the $729,000 accumulated on the
Balance Sheet in Other Assets as of December 31, 2000, were charged to
54
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
earnings in 2001. Under existing agreements Mission is not required to pay any
additional mining venture costs and there were no such charges in 2002.
Goodwill
The Financial Accounting Standards Board ("FASB") approved Statement of
Financial Accounting Standards ("SFAS") No. 142, Goodwill and Other Intangible
Assets in June 2001. This pronouncement requires that intangible assets with
indefinite lives, including goodwill, cease being amortized and be evaluated on
an annual basis for impairment. The Company adopted SFAS No. 142 on January 1,
2002 at which time the Company had unamortized goodwill, related to the Bargo
merger, in the amount of $15.1 million and unamortized identifiable intangible
assets in the amount of $374,300, all subject to the transition provisions.
Upon adoption of SFAS No. 142, $277,000 of workforce intangible assets recorded
as unamortized identifiable assets was subsumed into goodwill and was not
amortized as it no longer qualified as a recognizable intangible asset.
The transition and impairment test for goodwill, effective January 1, 2002,
was performed in the second quarter of 2002. As of January 1, 2002, the
Company's fair value exceeded the carrying amount; therefore goodwill was not
impaired. Mission designated December 31st as the date for its annual test.
Based upon the results of such test at December 31, 2002, goodwill was fully
impaired and a write-down of $16.7 million was recorded. The valuation was
based on the following procedures and information:
. compute a cash flow model of the Company's oil and gas assets using
third party information and verification;
. apply risking parameters to the various categories of oil and gas
reserves using reputable third party sources for risk profile;
. apply a discount rate to such valuation that approximates Mission's cost
of capital and cost of debt;
. reduce this valuation by Mission's net debt to ascertain the equity fair
value; and
. compare book equity to fair value equity.
The changes in the carrying amount of goodwill for the period ended December
31, 2002, are as follows (amounts in thousands):
Intangible Total Goodwill
Goodwill Assets and Intangibles
-------- ---------- ---------------
Balance, December 31, 2001.................. $ 15,061 $ 375 $ 15,436
Transferred to goodwill..................... 277 (277) --
Amortization of lease....................... -- (98) (98)
Merger purchase price allocation adjustments 1,341 -- 1,341
Goodwill impairment......................... (16,679) -- (16,679)
-------- ----- --------
Balance, December 31, 2002.................. $ -- $ -- $ --
======== ===== ========
SFAS No. 142 requires disclosure of what reported income before
extraordinary items and net income would have been in all periods presented
exclusive of amortization expense (including any related tax effects)
recognized in those periods related to goodwill, intangible assets that are no
longer being amortized, any deferred credit related to excess over cost equity
method goodwill, and changes in amortization periods for intangible
55
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
assets that will continue to be amortized (including related tax effects).
Similarly adjusted per share amounts are also required to be disclosed for all
periods presented. The following table presents the required disclosures
concerning adjusted income for the year ended December 31, 2001 (amounts in
thousands):
Year Ended
December 31, 2001
-----------------
Net income (loss)............................................. $(30,945)
Exclude goodwill amortization................................. 986
--------
Net income (loss) exclusive of amortization................... $(29,959)
========
Net income (loss) exclusive of amortization per share......... $ (1.49)
Net income (loss) exclusive of amortization per share--diluted $ (1.49)
Comprehensive Income
Comprehensive income includes all changes in a company's equity except those
resulting from investments by owners and distributions to owners. The Company's
total comprehensive income for the twelve months ended December 31, 2002 and
2001 was as follows (in thousands):
Twelve Months Ended
December 31,
------------------
2002 2001
-------- --------
Net income (loss)..................................................... $(38,484) $(30,945)
Cumulative effect attributable to adoption of SFAS No. 133, net of tax -- (19,328)
Hedge accounting for derivative instruments, net of tax............... (6,481) 21,614
-------- --------
Comprehensive income (loss)........................................... $(44,965) $(28,659)
======== ========
The accumulated balance of other comprehensive income related to cash flow
hedges, net of taxes, is as follows (in thousands):
Balance at January 1, 2001............ $ --
Cumulative effect of accounting change (19,328)
Net gains on cash flow hedges......... 13,919
Reclassification adjustments.......... 14,934
Tax effect on hedge activity.......... (7,239)
--------
Balance at December 31, 2001.......... 2,286
Net gains (losses) on cash flow hedges (341)
Reclassification adjustments.......... (8,323)
Tax effect on hedge activity.......... 2,183
--------
Balance at December 31, 2002.......... $ (4,195)
========
Derivative Instruments and Hedging Activities
Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. 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
56
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
results on the hedged item in the 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.
New Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for
Asset Retirement Obligations, which provided accounting requirements for
retirement obligations associated with tangible long-lived assets, including:
. the timing of liability recognition;
. initial measurement of liability;
. allocation of asset retirement cost to expense;
. subsequent measure of the liability; and
. financial statement disclosures.
Statement 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 obligation is added to the carrying amount of the oil and gas
properties and this additional carrying amount is depreciated over the life of
the properties. If the obligation is settled for other than the carrying amount
of the liability, the Company will recognize a gain or loss on settlement.
The Company is required and plans to adopt the provisions of Statement No.
143 for the quarter ending March 31, 2003. To accomplish this, the Company must
identify all legal obligations for asset retirement obligations, if any, and
determine the fair value of these obligations on the date of adoption. The
determination of fair value is complex and will require the Company to gather
market information and develop cash flow models. Additionally, the Company will
be required to develop processes to track and monitor these obligations. The
Company expects to record an asset retirement liability of between $40.0
million and $50.0 million and a loss from a change in accounting method of
between $1.0 million and $5.0 million in the quarter ended March 31, 2003.
SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statements No. 13 and Technical Corrections, was issued in April 2002.
SFAS No. 145 amends existing guidance on reporting gains and losses on the
extinguishments of debt to prohibit the classification of the gain or loss as
extraordinary, as the use of such extinguishments have become part of the risk
management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to
require sale-leaseback accounting for certain lease modifications that have
economic effects similar to sale-leaseback transaction. The provision of the
Statement related to the rescission of Statement No. 4 is applied in fiscal
years beginning after May 15, 2002. Earlier application of these provisions is
encouraged. The provisions of Statement related to Statement No. 13 were
effective for transactions occurring after May 15, 2002, with early application
encouraged. The adoption of SFAS No. 145 does not currently affect Mission's
financial statements, however, its provisions could impact the treatment of
future transactions.
SFAS No. 146, Accounting for Exit or Disposal Activities, was issued in June
2002. SFAS No. 146 addresses significant issues regarding the recognition,
measurement, and reporting of costs that are associated
57
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
with exit and disposal activities, including restructuring activities that are
currently accounted for pursuant to the guidance set forth in EITF Issue No.
94-3, Liability Recognition of Certain Employee Termination Benefits and Other
Costs to Exit an Activity. SFAS No. 146 is effective for the exit and disposal
activities initiated after December 31, 2002. The Company will apply SFAS No.
146 as appropriate to future activities.
In November 2002, FASB issued Interpretation No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107
and a rescission of FASB Interpretation No. 34. This interpretation elaborates
on the disclosures to be made by a guarantor in its interim and annual
financial statements about its obligations under guarantees issued. The
interpretation also clarifies that a guarantor is required to recognize, at
inception of a guarantee, a liability for the fair value of the obligation
undertaken. The initial recognition and measurement provisions of the
interpretation are applicable to guarantees issued or modified after December
31, 2002 and are not expected to materially effect our financial statements.
The disclosure requirements are effective for financial statements of interim
and annual periods ending after December 15, 2002.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation--Transition and Disclosure, an amendment of SFAS No. 123, that
provides alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements. Some of
the disclosure modifications are required for fiscal years ending after
December 15, 2002 and are included in the notes to consolidated financial
statements.
FASB issued Interpretation No. 46, Consolidation of Variable Interest
Entities, an interpretation of APB No. 51, in January 2003. This interpretation
addresses the consolidation by business enterprises of variable interest
entities as defined in the interpretation. The interpretation applies
immediately to variable interest entities created after January 31, 2003, and
to variable interests in variable interest entities obtained after January 31,
2003. We do not own an interest in any variable interest entities; therefore,
this interpretation is not expected to have a material effect on our financial
statements.
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 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 May 16, 2001, Bellwether Exploration Company merged with Bargo Energy
Company and changed its name to Mission Resources Corporation. Under the merger
agreement, Bargo shareholders and option holders
58
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
received a combination of cash and Mission common stock. The merger was
accounted for using the purchase method of accounting and was financed through
the issuance of $80.0 million, or 9.5 million shares, of Mission common stock
to Bargo option holders and shareholders, and an initial $166.0 million in
borrowings under a new credit facility ("Credit Facility"). Borrowings under
the Credit Facility were used as follows:
. to pay the cash portion of the purchase price to holders of Bargo common
stock and options,
. to pay the amount incurred by Bargo in redeeming its preferred stock
immediately prior to the merger,
. to refinance Bargo's and Bellwether's then-existing credit facilities, and
. to pay transaction costs.
Initially, the $280.9 million adjusted purchase price allocated to the
acquired assets was $4.1 million to unproved properties, $255.7 million to
proved properties, $1.1 million to current drilling projects, $17.7 million to
goodwill and intangible assets and $2.3 million to current assets, current
liabilities and other non-current assets. The Company also acquired a 10.11%
ownership in the East Texas Salt Water Disposal Company.
On May 17, 2001, the Company purchased oil and gas properties in south
Louisiana for a gross sales price of $21.5 million.
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 23% of the shares of Torch on a fully diluted basis.
As of December 31, 2002, the Company was party to a Master Service Agreement
dated October 1, 1999, the ("MSA"), and two service contracts under which Torch
administers certain activities of the Company including the operation of oil
and gas properties and oil and gas marketing. Previously, the Company was party
to six service contracts with Torch, but four were terminated in 2002 and 2001.
A $620,000 termination fee was paid on the Corporate Services Agreement and was
recognized as part of general and administrative expense in the 2001 Statement
of Operations. Effective February 1, 2003, the contract covering operation of
oil and gas properties was terminated. Effective April 1, 2003 the contract for
marketing of Mission's oil and gas commodities will terminate. Only the
termination of the contract covering operations of oil and gas properties
required a fee, which was $75,000. As a result of the termination of all
previous service contracts with Torch, the MSA will effectively terminate on
April 1, 2003.
Fees paid to Torch for marketing services were $343,000, $417,000, and
$563,000, in periods ended December 31, 2002, 2001 and 2000, respectively.
Sales to Torch accounted for approximately 1%, 32% and 24% of fiscal year 2002,
2001 and 2000 oil and gas revenues, respectively. Fees paid to Torch for
operating our oil and gas properties were $1.4 million, $1.5 million and $1.0
million for the years ended December 31, 2002, 2001 and 2000, respectively.
Torch was the operator of the Snyder Gas Plant. In periods ended December
31, 2001 and 2000, the fees paid by the Company to Torch were $74,000 and
$96,0000, respectively. There were no such fees in 2002 because the gas plant
was sold in 2001. Torch provided services in prior periods for the evaluation
of potential property acquisitions and due diligence conducted in conjunction
with acquisitions closed at the Company's request. The Company was charged
$685,000 and $1.3 million for these costs in periods ended December 31, 2001
and 2000, respectively.
59
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Mission currently uses an Oracle platform through a hosting agreement,
effective July 1, 2002, with Novistar, previously a subsidiary of Torch.
Approximately $373,000 was paid to Novistar in 2002. On January 15, 2003 it was
announced that Novistar merged with Paradigm Technologies, a Petroleum Place
company, creating P2 Energy Solutions. As a result of this merger, Torch owns
38% of P2 Energy Solutions.
Milam Energy, LP ("Milam") is a 51% working interest owner with the Company
in several south Louisiana properties. Torch is a majority owner of Milam, and
J.P. Bryan, a member of Mission's Board of Directors until October 2002 is also
a managing director and stockholder of Torch. As of December 31, 2002, Milam
owed the Company approximately $570,000 in joint interest billings and cash
calls related to these properties. The receivable is reflected on the accounts
receivable and accrued revenues line of the consolidated Balance Sheet. A
portion of the outstanding receivable is past due, however, pursuant to an
agreement between the parties effective March 1, 2003. Milam made a $480,000
payment on March 12, 2003. The terms also provide for Milam to timely pay
Mission its joint interest billings and cash calls through July 2003.
In 2002, as part of an effort to improve liquidity, the Company sold
interests in various oil and gas fields through a series of competitive bids.
In July 2002, in one of those transactions, the Company sold interests in
several properties located in New Mexico to Chisos, LTD ("Chisos"). J.P. Bryan,
a member of Mission's board of directors until October 2002, is the President
and sole owner of Chisos. Over 25 companies requested information packages on
this sale and four submitted bids on these properties. The bid from Chisos was
$4.0 million, which exceeded all others by $250,000 and additionally 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.
Pursuant to a separation agreement between the Company and J. Darby Sere, a
former senior executive, in August 1999, the executive entered into a
non-recourse promissory note with a principal amount of $332,872. The loan
bears interest at an annual rate of 7% and was due and payable on August 23,
2002. After the due date all accrued interest was written-off and future
accruals ceased. The loan value was reduced to $32,000 at December 31, 2002,
the market value of the 78,323 Mission Resources shares that secured the loan.
The Company has not deemed the loan to be in default and anticipates that more
of the balance can be collected over time, or will be realized with the
appreciation in the value of the stock.
In connection with the reorganization of the Company'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 will be 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 have 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
60
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
them "whole" on a net after-tax basis. Messrs. Manner and Clarkson also agreed
to provide certain consulting services to the Company following their
separation dates. In January 2003, Mr. Manner received a pay-out in the sum of
$314,852 from the Company's Deferred Compensation Plan made up primarily of
deferred salary and bonuses under the terms of the plan.
5. Stockholders' Equity
Common and Preferred Stock
The Certificate of Incorporation of the Company initially authorized the
issuance of up to 30,000,000 shares of common stock and 1,000,000 shares of
preferred stock, the terms, preferences, rights and restrictions of which are
established by the Board of Directors of the Company.
In May 2001, the number of authorized shares was increased to 60 million
shares of common stock and 5 million shares of preferred stock. Certain
restrictions contained in the Company's loan agreements limit the amount of
dividends that may be declared. There is no present plan to pay cash dividends
on common stock as the Company intends to reinvest its cash flows for continued
growth of the Company.
A tax benefit related to the exercise of employee stock options of $240,000
in 2001 and $95,000 in 2000 was allocated directly to additional paid in
capital. Such benefit was not material in year 2002.
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 million
assigned value of such shares was included in the purchase price. Concurrent
with the merger, all Bellwether employees who held stock options were
immediately vested in those options upon closing of the merger. The expense was
calculated as the excess of the stock price on the merger date over the
exercise price of the option. An additional $102,000 and $799,000 of
compensation expense was recognized in the years ended December 31, 2002 and
2001, respectively, as a result of staff reductions.
Shareholder Rights Plan
In September 1997, the Company adopted a shareholder rights plan to protect
Mission's shareholders from coercive or unfair takeover tactics. Under the
shareholder rights plan, each outstanding share of Mission's common stock and
each share of subsequently issued Mission common stock has attached to it one
right. The rights become exercisable if a person or group acquires or announces
an intention to acquire beneficial ownership of 15% or more of the outstanding
shares of common stock without the prior consent of the Company. When the
rights become exercisable each holder of a right will have the right to
receive, upon exercise of the right, a number of shares of common stock of the
Company which, at the time the rights become exercisable, have a market price
of two times the exercise price of the right. The Company 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.
61
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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. The Company's
reconciliation is as follows (amounts in thousands, except per share amounts):
Year Ended December 31, 2002 Year Ended December 31, 2001
------------------------- -------------------------
Income Shares Per Share Income Shares Per Share
-------- ------ --------- -------- ------ ---------
Net loss.......................... $(38,484) $(30,945)
-------- ------ ------ -------- ------ ------
Loss per common share............. $(38,484) 23,586 $(1.63) $(30,945) 20,051 $(1.54)
Effect of dilutive securities:
Options & warrants................ -- -- -- --
-------- ------ ------ -------- ------ ------
Loss per common share--diluted.... $(38,484) 23,586 $(1.63) $(30,945) 20,051 $(1.54)
======== ====== ====== ======== ====== ======
Year Ended December 31, 2000
-------------------------
Income Shares Per Share
-------- ------ ---------
Net income........................ $ 32,208
-------- ------ ------
Earnings per common share......... $ 32,208 13,899 $ 2.32
Effect of dilutive securities:
Options & warrants................ -- 276
-------- ------ ------
Earnings per common share--diluted $ 32,208 14,175 $ 2.27
======== ====== ======
In periods of loss, diluted earnings per share were not calculated since the
issuance or conversion of additional securities would have had an antidilutive
effect. Options and warrants equal to 1,050,500 in 2002, 2,247,000 in 2001 and
584,500 in 2000 that could potentially dilute basic earnings per share in the
future were not included in the computation of diluted earnings per share
because to do so would have been antidilutive.
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 $1,905,000.
These treasury shares are reported at cost as a reduction to Stockholders'
Equity.
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. In May 2001, the number of shares available for issuance under the
1996 Stock Incentive Plan was increased by 2.0 million. These stock options may
be granted subject to terms ranging from 6 to 10 years at a price equal to the
fair market value of the stock at the date of grant. At December 31, 2002,
there were 936,334 options available for grants.
62
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
A summary of activity in the stock option plans is set forth below:
Option Price
Range
Number of ------------
Shares Low High
---------- ----- ------
Balance at December 31, 1999.... 1,528,000 $3.34 $12.38
Granted...................... 917,500 $4.25 $ 8.75
Surrendered.................. (51,999) $3.34 $ 7.97
Exercised.................... (90,835) $3.34 $ 7.63
----------
Balance at December 31, 2000.... 2,302,666 $3.34 $12.38
Granted...................... 1,984,000 $5.71 $ 8.80
Surrendered.................. (124,500) $4.59 $12.38
Exercised.................... (177,331) $3.34 $ 7.63
----------
Balance at December 31, 2001.... 3,984,835 $3.34 $12.38
Granted...................... 2,205,000 $0.31 $ 3.28
Surrendered.................. (2,974,335) $2.24 $12.38
Exercised.................... -- -- --
----------
Balance at December 31, 2002.... 3,215,500 $0.31 $10.31
==========
Exercisable at December 31, 2002 1,592,169 $0.31 $10.31
==========
In 2002, many employees voluntarily surrendered out of the money options.
The company intends to issue more options in 2003.
Detail of stock options outstanding and options exercisable at December 31,
2002 follows:
Outstanding Exercisable
---------------------------- ------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Life Exercise Exercise
Range of Exercise Prices Number (Years) Price Number Price
------------------------ --------- --------- -------- --------- --------
1994 Plan $0.38 to $ 6.38 479,000 8.8 $0.96 162,335 $1.73
1996 Plan $3.34 to $12.38 2,736,500 8.9 $2.66 1,429,834 $4.17
--------- ---------
Total................. 3,215,500 1,592,169
========= =========
The estimated weighted average fair value per share of options granted
during 2002, 2001 and 2000 was $0.58, $3.15, and $12.75, respectively. The fair
value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions.
. For 2002, expected stock price volatility of 160%; a risk free interest
rate of 3.9%; and an average expected option life of 10 years
. For 2001, expected stock price volatility of 69%; a risk free interest
rate of 5.3%; and an average expected option life of 10 years
. For 2000, expected stock price volatility of 65%; a risk free interest
rate of 5.1%; and an average expected option life of 10 years
63
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
Recently, as shown on the following tables, the Company has also entered into
some commodity swaps that fix the NYMEX price to be received. Hedging
activities decreased revenues by $342,000, $13.4 million and $24.5 million for
the years 2002, 2001 and 2000, respectively.
The Company's realized price for natural gas per MCF is generally $0.11 less
than the NYMEX MMBTU price. The Company's realized price for oil is generally
$0.95 per BBL less than NYMEX. Realized prices differ from NYMEX as a result of
factors such as the location of the property, the heating content of natural
gas and the quality of oil. The oil differential stated above excludes the
impact of Point Pedernales field production for which the Company's selling
price is capped at $9.00 per BBL. The Point Pedernales field was sold in March
2003.
In May 2002, several existing oil collars were cancelled. New swaps and
collars, hedging forecast oil production were acquired. The Company paid
approximately $3.3 million dollars to counter parties, the fair value of the
oil price collars at that time, in order to cancel the transactions. The
cancellation of these hedges did not have an immediate impact on income. As
required by SFAS No. 133 a $418,000 amount related to the cancelled hedges had
not yet been recognized in earnings. Such amount is being amortized from Other
Comprehensive Income ("OCI") over the 19-month life of the cancelled hedges,
leaving $264,000 at December 31, 2002.
In October, the Company elected to de-designate all existing hedges and
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 allowed for time value to be adjusted to income
quarterly. By using the DIG G-20 approach because the Company's collars and
swaps meet specific criteria, the time value component is included in OCI and
earnings variability is reduced. Both the realized and unrealized gains or
losses related to these de-designated hedges at October 15, 2002 will be
amortized over the 5 quarters remaining. The amount remaining in OCI, or the
unrealized loss, related to the de-designated hedges was approximately $4.6
million at October 15, 2002. The amount of unrealized loss is being amortized
over the remaining 15 month life of the hedges, leaving approximately $3.6
million at December 31, 2002.
64
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following tables detail the cash flow commodity hedges that were in
place at December 31, 2002.
Oil Hedges
NYMEX NYMEX
Price Price
BBLS Total Floor/Swap Ceiling
Period Per Day BBLS Type Avg. Avg.
------ ------- ------- ---- ---------- -------
First Qtr. 2003. 4,000 360,000 Swap $24.82 n/a
Second Qtr. 2003 4,000 364,000 Swap $24.31 n/a
Third Qtr. 2003. 3,500 322,000 Swap $23.95 n/a
Fourth Qtr. 2003 3,500 322,000 Swap $23.59 n/a
Gas Hedges
NYMEX NYMEX
Price Price
MMBTU Total Floor Ceiling
Period Per Day MMBTU Type Avg. Avg.
------ ------- --------- ------ ----- -------
First Qtr. 2003. 15,000 1,370,000 Collar $3.24 $4.64
Second Qtr. 2003 15,000 1,365,000 Collar $3.18 $4.02
Third Qtr. 2003. 15,000 1,380,000 Collar $3.19 $4.10
Fourth Qtr. 2003 15,000 1,380,000 Collar $3.24 $4.54
First Qtr. 2004. 5,000 455,000 Collar $3.90 $5.25
Second Qtr. 2004 5,000 455,000 Collar $3.70 $4.08
Third Qtr. 2004. 5,000 400,000 Collar $3.70 $4.04
Fourth Qtr. 2004 5,000 400,000 Collar $3.85 $4.23
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 by Mission's $1.3 million payment to the
counter party.
7. Determination of Fair Values of Financial Instruments
Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The interest rate swap and the commodity
derivatives 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, 2002 and 2001
(in thousands).
December 31, 2002 December 31, 2001
--------------------- ---------------------
Carrying Approximate Carrying Approximate
Value Fair Value Value Fair Value
--------- ----------- --------- -----------
Assets (Liabilities):
Long-term debt: (See Note 8)
Bank Credit Facility............................. $ -- $ -- $ (35,000) $ (35,000)
Senior Subordinated Notes, excluding $1.4 million
unamortized premium on $125.0 million bonds.... $(225,000) $(135,900) $(225,000) $(202,500)
65
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
8. Long-Term Debt
Long-term debt is comprised of the following at December 31, 2002 and 2001
(in thousands):
December 31, December 31,
2002 2001
------------ ------------
Credit facility.................................... $ -- $ 35,000
10 7/8% senior subordinated notes.................. 225,000 225,000
-------- --------
Subtotal........................................... 225,000 260,000
Premium on $125.0 million senior subordinated notes 1,431 1,695
-------- --------
Long-term debt..................................... $226,431 $261,695
======== ========
Debt maturities by fiscal year are as follows (amounts in thousands):
2003...... $ --
2004...... --
2005...... --
2006...... --
2007...... 225,000
Thereafter --
--------
$225,000
========
Credit Facility
Mission is party to a $150.0 million credit facility with a syndicate of
lenders. The Credit Facility is a revolving facility, expiring May 16, 2004,
which allows Mission to borrow, repay and re-borrow under the facility from
time to time. The total amount which may be borrowed under the facility is
limited by the borrowing base periodically set by the lenders based on
Mission's oil and gas reserves and other factors deemed relevant by the
lenders. At December 31, 2002, Mission's borrowing base was $40.0 million. The
Credit Facility was recently amended on October 7, 2002, reducing the maximum
amount available under the Credit Facility from $200 million to $150 million.
This modification does not limit the rights of the parties to initiate interim
borrowing base redeterminations in accordance with the Credit Facility. As a
result of the reduction in borrowing capacity, approximately $412,000 of
previously capitalized deferred financing costs related to the $200 million
Credit Facility were charged to interest expense in the fourth quarter of 2002.
Mission paid interest on the Credit Facility borrowings during 2002 at an
average interest rate of 3.9%. Future borrowings under the Credit Facility bear
an annual interest rate, at Mission's election, equal to either:
. the Eurodollar rate, plus an applicable margin from 1.5% to 2.5%; or
. the greater of (i) the prime rate, as determined by Chase Manhattan Bank,
or (ii) the federal funds rate plus 0.5%, plus a maximum of 1.0%.
The applicable margin for interest payable on outstanding borrowings is
based on the utilization rate as a percentage of the total amount of funds
borrowed under the Credit Facility to the borrowing base and Mission's long
term debt rating. Commitment fees and letter of credit fees under the Credit
Facility are also based on Mission's utilization rate and long-term debt
rating. Commitment fees range from 0% to 0.5% on the unused portion of the
Credit Facility. Letter of credit fees range from 0% to 2.5% of the unused
portion of the $20.0 million letter of credit sub-facility.
66
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Credit Facility contains negative covenants that limit Mission's
ability, among other things, to:
. incur additional debt;
. pay dividends on stock, redeem stock or redeem subordinated debt;
. make investments;
. create liens in favor of senior subordinated debt and subordinated debt;
. sell assets;
. sell capital stock of subsidiaries;
. guarantee other indebtedness;
. enter into agreements that restrict dividends from subsidiaries;
. merge or consolidate; and
. enter into transaction with affiliates.
In addition, the Credit Facility requires that certain financial covenants
be maintained:
. a minimum interest coverage ratio of earnings before interest,
depreciation, depletion, amortization, income tax, and extraordinary
items, or EBITDAX, to net interest expense of at least:
Fiscal Quarter Interest Coverage Ratio
-------------- -----------------------
09/30/02 through 03/31/03 1.75 to 1.00
04/01/03 through 06/30/03 1.90 to 1.00
07/01/03 through 09/30/03 2.10 to 1.00
10/01/03 through 12/31/03 2.30 to 1.00
01/01/04 and thereafter.. 2.50 to 1.00
. an asset coverage or current ratio (which includes availability) of at
least 1.0 to 1.0;
. a maximum ratio of senior debt to EBITDAX of 2.0 to 1.0; and
. a maximum ratio of total debt to EBITDAX:
Fiscal Quarter Total Debt to EBITDAX
-------------- ---------------------
09/30/02 through 12/31/02 5.50 to 1.00
01/01/03 through 03/31/03 5.00 to 1.00
04/01/03 through 06/30/03 4.75 to 1.00
07/01/03 through 09/30/03 4.50 to 1.00
10/01/03 through 12/31/03 4.00 to 1.00
01/01/04 and thereafter.. 3.50 to 1.00
On December 31, 2002, the Company had no outstanding borrowings and was in
compliance with its covenants under the Credit Facility.
Senior Subordinated Notes
In April 1997, the Company issued $100.0 million of 10 7/8% senior
subordinated notes due 2007. On May 29, 2001, the Company issued an additional
$125.0 million of senior subordinated notes due 2007 with identical terms to
the notes issued in April 1997 (collectively "Notes") at a premium of $1.9
million. The
67
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
premium is amortized as a reduction of interest expense over the life of the
Notes so that the effective interest rate on these additional Notes is 10.5%.
The premium is shown separately on the Balance Sheet. Interest on the Notes is
payable semi-annually on April 1 and October 1. The Notes will be redeemable,
in whole or in part, at the option of the Company at any time on or after April
1, 2002 at 105.44% which decreases annually to 100.00% on April 1, 2005 and
thereafter, plus accrued and unpaid interest. In the event of a change of
control of the Company, as defined in the indenture, each holder of the Notes
will have the right to require the Company to repurchase all or part of such
holder's Notes at an offer price in cash equal to 101.0% of the aggregate
principal amount thereof, plus accrued and unpaid interest to the date of
purchase. The Notes contain certain covenants, including limitations on
indebtedness, liens, compliance with requirements of existing indebtedness,
dividends, repurchases of capital stock and other payment restrictions
affecting restricted subsidiaries, issuance and sales of restricted subsidiary
stock, dispositions of proceeds of asset sales and restrictions on mergers and
consolidations or sales of assets. As of December 31, 2002, the Company was in
compliance with its covenants under the Notes. In the event the Company becomes
out of compliance with its Credit Facility covenants, the Notes will not be
impacted unless borrowings under the Credit Facility are in excess of $10.0
million.
9. Income Taxes
Income tax expense (benefit) is summarized as follows (in thousands):
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
Current
Federal.............. $ (734) $ -- $ 67
State................ -- 595 18
Deferred
Federal.............. (10,846) (10,488) (13,506)
Foreign.............. -- (300) 300
State................ -- 1,138 899
-------- -------- --------
Total income tax benefit $(11,580) $ (9,055) $(12,222)
======== ======== ========
68
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The tax effect of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities at December 31, 2002 and
2001 is as follows:
December 31, December 31,
2002 2001
------------ ------------
Net operating loss carryforwards............ $ 26,597 $ 12,487
Percentage depletion carryforwards.......... 279 279
Alternative minimum tax credit carryforwards 8 742
Tax effect of hedging activities............ 2,259 --
State income taxes.......................... 3,140 2,134
Impairment of interest in Carpatsky......... 2,186 2,186
Other....................................... 1,869 1,689
-------- --------
Gross deferred tax assets................... 36,338 19,517
Less valuation allowance.................... (5,326) (4,320)
-------- --------
Deferred income tax assets.................. 31,012 15,197
-------- --------
Property, plant and equipment............... (47,958) (45,143)
Tax effect of hedging activities............ -- (1,231)
Total deferred income tax liability......... (47,958) (46,374)
-------- --------
Net deferred income tax asset (liability)... $(16,946) $(31,177)
======== ========
At December 31, 2000, the Company determined that it was more likely than
not that the deferred tax assets would be realized based on current projections
of taxable income due to higher commodity prices at year end 2000, and the
valuation allowance was decreased by $19.8 million to zero. At December 31,
2001, however, the Company determined that a portion of the deferred tax assets
would not be realized. In assessing the realizability of the deferred tax
assets, management considers whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The ultimate
realization of deferred tax assets is dependent upon the generation of future
taxable income during the periods in which those temporary differences become
deductible. Based upon the projections for future state taxable income,
management believes it is more likely than not that the Company will not
realize its deferred tax asset related to state income taxes. Based upon the
projections of future taxable income, 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, because the reversal of the
deferred tax asset will result in a capital loss for federal income tax
purposes, and the Company does not project any transactions resulting in
capital gains to offset the capital loss. The valuation allowance is therefore
$5.3 million and $4.3 million for the years ending December 31, 2002 and 2001,
respectively.
A tax benefit related to the cumulative effect of a change in accounting
method of $1,663,000 was recorded and shown as part of the cumulative effect on
the consolidated statements of operations in 2001.
A tax benefit related to the exercise of employee stock options of
approximately $240,000 and $95,000 was allocated directly to additional paid-in
capital in 2001 and 2000, respectively. Such benefit was not material in 2002.
69
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
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:
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
Statutory federal income tax rate............... 35.0% 35.0% 34.0%
Increase (decrease) in tax rate resulting from:
State income taxes, net of federal benefit... 2.0% (1.3%) 3.0%
Foreign income taxes, net of federal benefit. -- 0.5% 1.0%
Non-deductible travel and entertainment......... (0.1%) (0.1%) 0.1%
Non-deductible goodwill amortization/impairment. (11.7%) (0.9%) --
Other........................................... (0.1%) -- --
Change in valuation allowance................... (2.0%) (8.9%) (99.3%)
----- ---- -----
23.1% 24.3% (61.2%)
===== ==== =====
The Company issued 9.5 million shares of its common stock on May 16, 2001 in
its acquisition of Bargo Energy Company. Management believes that the merger
with Bargo was not an ownership change as defined in section 382 of the
Internal Revenue Code. Therefore, the Company last had an ownership change in
1994 with the issuance of 3.4 million shares of its common stock. A change of
stock ownership in the future by a significant shareholder of the Company may
cause an ownership change, which would affect the Company's ability to utilize
its net operating loss ("NOL") carryforwards in the future. Section 382 of the
Internal Revenue Code significantly limits the amount of NOL and investment tax
credit carryforwards that are available to offset future taxable income and
related tax liability when a change in ownership occurs.
At December 31, 2002, the Company had net operating loss carryforwards of
approximately $75.9 million, which will expire in future years beginning in
2003 and ending in 2022 as shown below.
($ in thousands)
----------------
2003...... $ 121
2004...... 1,371
2005...... 1,242
2006...... 1,538
2007...... 401
Thereafter 71,318
-------
Total..... $75,991
=======
10. Commitments and Contingencies
Lease Commitments
At December 31, 2002, the minimum future payments under the terms of the
Company's office space operating leases are as follows:
Year Ended December 31 ($ in thousands)
---------------------- ----------------
2003 597
2004 601
2005 601
2006 601
2007 601
70
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Rent expense was $685,000, $551,000, and $509,000 in 2002, 2001 and 2000,
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 Statement of Operations.
In early 2002, Mission settled for $98,000 Garza Energy Trust, et al. V.
Coastal Oil and Gas Corporation, et al. Mission had accrued $250,000 for the
judgment in 2001, but later arrived at this more favorable settlement.
The Company routinely obtains bonds to cover its obligations to plug and
abandon oil and gas wells. In instances where the Company purchases or sells
oil and gas properties, the parties to the transaction routinely include an
agreement as to who will be responsible for plugging and abandoning any wells
on the property and restoring the surface. In those cases, the Company will
obtain new bonds or release old bonds regarding its plugging and abandonment
exposure based on the terms of the purchase and sale agreement. However, if a
party to the purchase and sale agreement defaults on its obligations to obtain
a bond or otherwise plug and abandon a well or restore the surface or if that
party becomes bankrupt, the landowner, and in some cases the state or federal
regulatory authority, may assert that the Company is obligated to plug the well
since it is in the "chain of title". The Company has been notified of such
claims from landowners and the State of Louisiana and is vigorously asserting
its rights under the applicable purchase and sale agreements to avoid this
liability. At this time, the Company has accrued a liability for approximately
$161,000 that it has agreed to contribute toward the proper abandonment and
cleanup of the Bayou fer Blanc field.
In 1993 and 1996 the Company entered into agreements with surety companies
and with Torch and Nuevo Energy Company ("Nuevo") whereby the surety companies
agreed to issue such bonds to the Company, Torch and/or Nuevo. However, Torch,
Nuevo and the Company agreed to be jointly and severally liable to the surety
company for any liabilities arising under any bonds issued to the Company,
Torch and/or Nuevo. The amount of bonds presently issued to Torch and Nuevo
pursuant to these agreements is approximately $35.2 million. 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.
11. Restructuring
During 2001 year the Company took several steps to restructure its
operations and improve its cost structure, including the reduction of staff by
almost 50% and the termination of several outsourcing contracts. The $2.1
million in costs associated with these plans was paid in 2002. In the latter
half of 2002, Mission's Chief
71
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 agreement, 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. Selected Quarterly Financial Data (amounts in thousands, except per share
data) (Unaudited):
Quarter Ended
--------------------------------------------
December 31, September 30, June 30, March 31,
2002 2002 2002 2002
------------ ------------- -------- ---------
Revenues...................... $ 27,327 $27,571 $28,266 $ 22,300
Operating income (loss)....... $(22,704) $(3,735) $(9,221) $(14,404)
Net income (loss)............. $(20,700) $(2,428) $(5,993) $ (9,363)
Loss per common share......... $ (0.88) $ (0.10) $ (0.25) $ (0.40)
Loss per common share--diluted $ (0.88) $ (0.10) $ (0.25) $ (0.40)
Quarter Ended
---------------------------------------------
December 31, September 30, June 30, March 31,
2001 2001 2001 2001
------------ ------------- -------- ---------
Revenue........................... $ 32,522 $40,497 $35,243 $33,815
Operating income.................. $(39,099) $ 1,429 $(9,432) $ 9,869
Net income........................ $ 29,260 $ 693 $(6,007) $ 3,629
Earnings per common share......... $ (1.24) $ 0.03 $ (0.32) $ 0.46
Earnings per common share--diluted $ (1.24) $ 0.03 $ (0.32) $ 0.44
The loss in the quarter ended December 31, 2002 includes the impact of a
$16.7 million goodwill impairment. The loss in the quarter ended June 30, 2001
reflects the loss on sale of Ecuador interests. The loss in the quarter ended
December 31, 2001 includes the impact of $27.0 million in pre-tax asset
impairments.
13. Pro forma
The merger with Bargo completed on May 16, 2001 significantly impacted the
future operating results of Mission Resources. The merger was accounted for as
a purchase, and the results of operations are included in Mission's results of
operations from May 16, 2001. The pro forma results are based on assumptions
and estimates and are not necessarily indicative of the Company's results of
operations had the transaction occurred as of January 1, 2000, or of those in
the future.
The following table presents the unaudited pro forma results of operations
as if the merger had occurred on January 1, 2000 and 2001, respectively
(amounts in thousands, except earnings per share):
Year Ended Year Ended
December 31, December 31,
2001 2000
------------ ------------
Revenues......................................................... $182,252 $226,260
Income before cumulative effective of change in accounting method $(26,054) $ 40,936
Net income (loss)................................................ $(28,821) $ 40,936
Net income (loss) per share...................................... $ (1.22) $ 1.75
Net income (loss) per share--diluted............................. $ (1.22) $ 1.73
72
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
14. Guarantees
The Company's subsidiaries, Mission E&P Limited Partnership, Mission
Holdings LLC, and Black Hawk Oil Company are guarantors under the indenture for
the $225.0 million 10 7/8% senior subordinated notes.
In 1993 and 1996 the Company entered into agreements with surety companies
and with Torch and Nuevo whereby the surety companies agreed to issue such
bonds to the Company, Torch and/or Nuevo. However, Torch, Nuevo and the Company
agreed to be jointly and severally liable to the surety company for any
liabilities arising under any bonds issued to the Company, Torch and/or Nuevo.
The amount of bonds presently issued to Torch and Nuevo pursuant to these
agreements is approximately $35.2 million. 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.
Typically, in a property sale the Company will retain liability for events
or occurrences that were known prior to the effective date of the sale, but not
otherwise. All other liabilities become the responsibility of the purchaser
after the effective date of the sale.
15. Subsequent Events (unaudited)
In March 2003, the Company sold its interests in the Point Pedernales field
to the operator of the property. This transaction divests Mission of all
California properties; however, the option to participate in future drilling at
Tranquillion Ridge was retained. The Company paid $1.8 million to the
purchaser, who in turn assumed the Company's environmental, plugging and
abandonment liabilities, estimated to be between $3 million and $5 million.
Mission Resources Corporation announced on March 28, 2003 that it had
acquired, in a private transaction with affiliates of Farallon Capital
Management, LLC, $97.6 million of its 10 7/8% senior subordinated notes (the
"Notes") for approximately $71.7 million plus accrued interest. Simultaneously
with the buyback, Mission has amended and restated its credit facility with new
lenders, led by Farallon Energy Lending, LLC.
The amended and restated senior secured credit facility (the "Facility") has
a term approximately 21 months and has initial availability of $80.0 million.
The Company has drawn the full $80.0 million. Approximately $75.0 million of
the drawn funds were used to acquire $97.6 million face amount of the Notes and
pay closing costs associated therewith. The remaining amount is available for
general corporate purposes. The Facility provides that an additional $10.0
million could be made available at the sole discretion of the lenders and that
if such additional advance were to be made, it could be used only for the
purpose of acquiring additional Notes. There can be no assurances that the
lenders will consent to this additional advance. The interest rate on the
Facility is 12% initially and will increase to 13% in early 2004. The Facility
allows the Company to put in place a revolving credit facility of up to $12.5
million with a third party subject to certain limitations.
73
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In February 2003, the Company cancelled its interest rate swap by paying the
counter party approximately $1.3 million, the then market value of the swap.
On March 26, 2003, Moody's lowered the Company's senior subordinated notes
credit rating to "Caa3" from "Caa1", lowered its senior implied rating to
"Caa1" from "B2" and lowered its senior secured debt rating to "B2" from "B1".
16. Segment Reporting
Through mid-2001, the Company's operations are concentrated primarily in
three segments: exploration and production of oil and natural gas in the United
States, in Ecuador and gas plants. The assets in Ecuador and two gas plants
were sold in 2001.
Year Ended December 31,
----------------------------
2002 2001 2000
-------- -------- --------
Sales to unaffiliated customers:
Oil and gas--US................................... $112,879 $131,358 $107,938
Oil and gas--Ecuador.............................. -- 1,877 4,315
Gas plants........................................ -- 4,456 6,070
-------- -------- --------
Total sales.................................... 112,879 137,691 118,323
Interest and other income (expense)............... (7,415) 4,386 957
-------- -------- --------
Total revenues................................. 105,464 142,077 119,280
======== ======== ========
Operating profit (loss) before income taxes:
Oil and gas--US................................... $ 16,768 $ 38,549 $ 40,983
Oil and gas--Ecuador.............................. -- (1,698) 719
Gas plants........................................ -- 2,338 3,393
Gain on gas plant sale............................ -- 1,124 --
-------- -------- --------
$ 16,768 $ 40,313 $ 45,095
Unallocated corporate expenses.................... 20,655 10,998 9,734
Interest expense.................................. 26,853 23,664 15,375
Mining venture costs.............................. -- 914 --
Loss on sale of Ecuador interests................. 2,645 12,724 --
Impairment expense................................ 16,679 27,057 --
Uncollectible gas revenue......................... -- 2,189 --
-------- -------- --------
Operating profit (loss) before income taxes....... $(50,064) $(37,233) $ 19,986
======== ======== ========
Identifiable assets:
Oil and gas--US................................... $300,719 $379,738 $125,586
Oil and gas--Ecuador.............................. -- -- 12,243
Gas plants........................................ -- -- 11,107
-------- -------- --------
$300,719 $379,738 $148,936
Corporate assets and investments.................. 41,685 68,026 72,609
-------- -------- --------
Total.......................................... $342,404 $447,764 $221,545
======== ======== ========
Capital expenditures:
Oil and gas--US................................... $ 21,439 $ 68,048 $ 76,242
Oil and gas--Ecuador.............................. -- 4,151 12,130
Gas plants........................................ -- 1,047 677
-------- -------- --------
$ 21,439 $ 73,246 $ 89,049
======== ======== ========
Depreciation, depletion amortization and impairments:
Oil and gas--US................................... $ 42,656 $ 41,895 $ 30,356
Oil and gas--Ecuador.............................. -- 504 745
Gas plants........................................ -- 1,025 1,211
-------- -------- --------
$ 42,656 $ 43,424 $ 32,312
======== ======== ========
74
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
16. Supplemental Information--(Unaudited)
Oil and Gas Producing Activities:
Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on estimates
of year-end oil and gas reserve quantities and estimates of future development
costs and production schedules. Reserve quantities and future production are
based primarily upon reserve reports prepared by the independent petroleum
engineering firms. The reserve reports were prepared by Ryder Scott Company for
the year ended December 31, 2000. The reserve reports for the year ended
December 31, 2001 were prepared by Ryder Scott Company, Netherland Sewell &
Associates, Inc., and T. J. Smith & Company, Inc. The reserve report for the
year ended December 31, 2002 were prepared by Netherland Sewell & Associates,
Inc. These estimates are inherently imprecise and subject to substantial
revision.
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.
75
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Costs Incurred (in thousands)
Year Ended December 31,
------------------------
2002 2001 2000
------- -------- -------
United States:
Property acquisition:
Proved properties*................ $ 850 $280,281 $ 5,065
Unproved properties............... -- 4,100 --
Exploration....................... 1,337 12,489 13,139
Development:
Proved developed properties....... 16,377 25,609 41,615
Proved undeveloped properties..... 2,876 6,462 16,423
------- -------- -------
$21,440 $328,941 $76,242
------- -------- -------
Ecuador:
Property acquisition:
Proved properties................. -- $ 249 $ 2,013
Unproved properties............... -- -- --
Development:
Proved developed properties....... -- 3,902 10,117
Proved undeveloped properties..... -- -- --
------- -------- -------
$ -- $ 4,151 $12,130
------- -------- -------
Worldwide:
Property acquisition:
Proved properties................. $ 850 $280,530 $ 7,078
Unproved properties............... -- 4,100 --
Exploration....................... 1,337 12,489 13,139
Development:
Proved developed properties....... 16,377 29,511 51,732
Proved undeveloped properties..... 2,876 6,462 16,423
------- -------- -------
$21,440 $333,092 $88,372
======= ======== =======
- --------
* 2001 total includes $56.6 million of deferred taxes related to the Bargo
merger.
Capitalized costs (in thousands):
Year Ended December 31,
----------------------
2002 2001
--------- ---------
Proved properties................................................... $ 766,975 $ 738,375
Unproved properties................................................. 8,369 15,530
--------- ---------
Total capitalized costs.......................................... 775,344 753,905
Accumulated depreciation, depletion, amortization and impairment. (474,625) (374,167)
--------- ---------
Net capitalized costs........................................ $ 300,719 $ 379,738
========= =========
76
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Results of operations for producing activities (in thousands):
Year Ended
December 31,
2002
------------
Revenues from oil and gas producing activities............................................ $112,879
Production costs.......................................................................... 51,987
Transportation costs...................................................................... 834
Income tax................................................................................ 21,020
Depreciation, depletion and amortization.................................................. 43,291
--------
Results of operations from producing activities (excluding corporate overhead and interest
costs).................................................................................. $ (4,253)
========
Year Ended December 31, 2001
---------------------------
United
States Ecuador Worldwide
-------- ------- ---------
Revenues from oil and gas producing activities............................... $131,358 $ 1,877 $133,235
Production expenses.......................................................... 48,134 3,071 51,205
Transportation costs......................................................... 73 -- 73
Income tax................................................................... 6,208 -- 6,208
Impairment expense........................................................... 20,811 -- 20,811
Depreciation, depletion and amortization..................................... 44,602 504 45,106
-------- ------- --------
Results of operations from producing activities (excluding corporate overhead
and interest costs)........................................................ $ 11,530 $(1,698) $ 9,832
======== ======= ========
Year Ended December 31, 2000
--------------------------
United
States Ecuador Worldwide
-------- ------- ---------
Revenues from oil and gas producing activities............................... $107,938 $4,315 $112,253
Production expenses.......................................................... 27,694 2,815 30,509
Disposition of hedges........................................................ 8,671 -- 8,671
Transportation costs......................................................... 234 36 270
Income tax................................................................... 15,574 -- 15,574
Depreciation, depletion and amortization..................................... 30,356 745 31,101
-------- ------ --------
Results of operations from producing activities (excluding corporate overhead
and interest costs)........................................................ $ 25,409 $ 719 $ 26,128
======== ====== ========
77
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's estimated total proved and proved developed reserves of oil
and gas are as follows:
Year Ended
December 31, 2002
-----------------------
Oil NGL Gas
Description (MBBL) (MBBL) (MMCF)
----------- ------- ------ -------
Proved reserves at beginning of year 39,538 2,060 154,082
Revisions of previous estimates..... (1,915) 251 (42,426)
Extensions and discoveries.......... 227 -- 537
Production.......................... (3,157) (266) (12,524)
Sales of reserves in-place.......... (12,093) (41) (18,178)
Purchase of reserves in-place....... 5 -- --
------- ----- -------
Proved reserves at end of year...... 22,605 2,004 81,491
======= ===== =======
Proved developed reserves--
Beginning of year................ 31,902 1,924 97,984
======= ===== =======
End of year...................... 16,965 1,711 45,210
======= ===== =======
78
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended
December 31, 2001
-----------------------
Oil NGL Gas
Description (MBBL) (MBBL) (MMCF)
----------- ------- ------ -------
United States
Proved reserves at beginning of year 9,669 1,655 74,729
Revisions of previous estimates..... (1,134) 488 (3,302)
Extensions and discoveries.......... 2,430 80 25,126
Production.......................... (3,140) (163) (17,597)
Sales of reserves in-place.......... (3,883) -- (15,927)
Purchase of reserves in-place....... 35,596 -- 91,053
------- ----- -------
Proved reserves at end of year...... 39,538 2,060 154,082
======= ===== =======
Proved developed reserves--
Beginning of year................ 9,073 1,508 68,757
======= ===== =======
End of year...................... 31,902 1,924 97,984
======= ===== =======
Ecuador:(1)
Proved reserves at beginning of year 7,812 -- --
Production.......................... (95) -- --
Sales of reserves in-place.......... (7,717) -- --
------- ----- -------
Proved reserves at end of year...... -- -- --
======= ===== =======
Proved developed reserves--.........
Beginning of year................ 2,135 -- --
======= ===== =======
End of year...................... -- -- --
======= ===== =======
Worldwide:
Proved reserves at beginning of year 17,481 1,655 74,729
Revisions of previous estimates..... (1,134) 488 (3,302)
Extensions and discoveries.......... 2,430 80 25,126
Production.......................... (3,235) (163) (17,597)
Sales of reserves in-place.......... (11,600) -- (15,927)
Purchase of reserves in-place....... 35,596 -- 91,053
------- ----- -------
Proved reserves at end of year...... 39,538 2,060 154,082
======= ===== =======
Proved developed reserves--
Beginning of year................ 11,208 1,508 68,757
======= ===== =======
End of year...................... 31,902 1,924 97,984
======= ===== =======
- --------
(1) The Company's Ecuador reserves were pursuant to a contract with the
Ecuadorian government under which the Company did not own the reserves but
had a contractual right to produce the reserves and receive revenues.
79
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended
December 31, 2000
----------------------
Oil NGL Gas
Description (MBBL) (MBBL) (MMCF)
----------- ------ ------ -------
United States
Proved reserves at beginning of year 10,827 2,069 130,079
Revisions of previous estimates..... 1,033 93 (21,291)
Extensions and discoveries.......... 613 4 18,418
Production.......................... (1,987) (219) (20,478)
Sales of reserves in-place.......... (817) (292) (31,999)
Purchase of reserves in-place....... -- -- --
------ ----- -------
Proved reserves at end of year...... 9,669 1,655 74,729
====== ===== =======
Proved developed reserves--
Beginning of year................ 9,990 2,032 108,491
====== ===== =======
End of year...................... 9,073 1,508 68,757
====== ===== =======
Ecuador:(1)
Proved reserves at beginning of year 3,884 -- --
Revisions of previous estimates..... (714) -- --
Production.......................... (174) -- --
Purchase of reserves in-place....... 4,817 -- --
Proved reserves at end of year...... 7,813 -- --
====== ===== =======
Proved developed reserves--
Beginning of year................ 245 -- --
====== ===== =======
End of year...................... 2,135 -- --
====== ===== =======
Worldwide:
Proved reserves at beginning of year 14,711 2,069 130,079
Revisions of previous estimates..... 319 93 (21,291)
Extensions and discoveries.......... 613 4 18,418
Production.......................... (2,161) (219) (20,478)
Sales of reserves in-place.......... (817) (292) (31,999)
Purchase of reserves in-place....... 4,817 -- --
------ ----- -------
Proved reserves at end of year...... 17,482 1,655 74,729
====== ===== =======
Proved developed reserves--
Beginning of year................ 10,235 2,032 108,491
====== ===== =======
End of year...................... 11,208 1,508 68,757
====== ===== =======
- --------
(1) The Company's Ecuador reserves were pursuant to a contract with the
Ecuadorian government under which the Company did not own the reserves but
had a contractual right to produce the reserves and receive revenues.
80
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Discounted future net cash flows (in thousands)
The standardized measure of discounted future net cash flows and changes
therein related to proved oil and gas reserves are shown below:
Year Ended December 31,
----------------------------------
2002 2001 2000
---------- ---------- ----------
United States:
Future cash flow.................. $1,075,050 $1,200,145 $ 950,121
Future production costs........... (405,251) (502,083) (203,464)
Future income taxes............... (125,094) (112,364) (183,139)
Future development costs.......... (74,034) (97,644) (36,874)
---------- ---------- ----------
Future net cash flows............. 470,671 488,054 526,644
10% discount factor............... (214,843) (192,483) (133,062)
---------- ---------- ----------
Standardized future net cash flows $ 255,828 $ 295,571 $ 393,582
========== ========== ==========
Ecuador:
Future cash flow.................. $ -- $ -- $ 174,632
Future production costs........... -- -- (60,899)
Future income taxes............... -- -- (37,793)
Future development costs.......... -- -- (27,595)
---------- ---------- ----------
Future net cash flows............. -- -- 48,345
10% discount factor............... -- -- (18,835)
---------- ---------- ----------
Standardized future net cash flows $ -- $ -- $ 29,510
========== ========== ==========
Worldwide:
Future cash flow.................. $1,075,050 $1,200,145 $1,124,753
Future production costs........... (405,251) (502,083) (264,363)
Future income taxes............... (125,094) (112,364) (220,932)
Future development costs.......... (74,034) (97,644) (64,469)
---------- ---------- ----------
Future net cash flows............. 470,671 488,054 574,989
10% discount factor............... (214,843) (192,483) (151,897)
---------- ---------- ----------
Standardized future net cash flows $ 255,828 $ 295,571 $ 423,092
========== ========== ==========
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands of dollars):
Year Ended
December 31,
2002
------------
Standardized measure--beginning of year...................................................... $295,571
Sales, net of production costs............................................................... (60,031)
Net change in prices and production costs.................................................... 160,132
Net change in income taxes................................................................... (2,635)
Extensions, discoveries and improved recovery, net of future production and development costs 3,803
Changes in estimated future development costs................................................ 4,459
Development costs incurred during the period................................................. 15,870
Revisions of quantity estimates.............................................................. (78,419)
Accretion of discount........................................................................ 29,557
Sales of reserves in-place................................................................... (56,875)
Changes in production rates and other........................................................ (55,604)
--------
Standardized measure--end of year............................................................ $255,828
========
81
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended December 31, 2001
------------------------------
United World
States Ecuador Wide
--------- -------- ---------
Standardized measure--beginning of year.................................... $ 393,582 $ 29,510 $ 423,092
Sales, net of production costs............................................. (83,151) 1,194 (81,957)
Purchases of reserves in-place............................................. 618,442 -- 618,442
Net change in prices and production costs.................................. (727,143) -- (727,143)
Net change in income taxes................................................. 30,994 18,577 49,571
Extensions, discoveries and improved recovery, net of future production and
development costs........................................................ 62,308 -- 62,308
Changes in estimated future development costs.............................. (27,152) -- (27,152)
Development costs incurred during the period............................... 21,584 3,736 25,320
Revisions of quantity estimates............................................ 18,376 -- 18,376
Accretion of discount...................................................... 39,358 2,950 42,308
Sales of reserves in-place................................................. (89,139) (53,017) (142,156)
Changes in production rates and other...................................... 37,512 (2,950) 34,562
--------- -------- ---------
Standardized measure--end of year.......................................... $ 295,571 $ -- $ 295,571
========= ======== =========
Year Ended December 31, 2000
------------------------------
United World
States Ecuador Wide
--------- -------- ---------
Standardized measure--beginning of year.................................... $ 191,604 $ 13,284 $ 204,888
Sales, net of production costs............................................. (80,244) (1,500) (81,744)
Purchases of reserves in-place............................................. -- 28,389 28,389
Net change in prices and production costs.................................. 375,242 (23,174) 352,068
Net change in income taxes................................................. (113,444) (14,430) (127,874)
Extensions, discoveries and improved recovery, net of future production and
development costs........................................................ 56,283 -- 56,283
Changes in estimated future development costs.............................. (4,942) (1,990) (6,932)
Development costs incurred during the period............................... 31,095 4,329 35,424
Revisions of quantity estimates............................................ (46,271) (6,787) (53,058)
Accretion of discount...................................................... 19,160 1,329 20,489
Sales of reserves in-place................................................. (34,697) -- (34,697)
Changes in production rates and other...................................... (204) 30,060 29,856
--------- -------- ---------
Standardized measure--end of year.......................................... $ 393,582 $ 29,510 $ 423,092
========= ======== =========
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 $31.17, $19.76,
and $26.80 per barrel and $4.74, $2.73, and $9.52 per MMBTU, for December 31,
2002, 2001, and 2000, respectively, adjusted to the wellhead to reflect
adjustments for transportation, quality and heating content. The foregoing
discounted future net cash flows do not include the effects of hedging or other
derivative contracts not specific to a property. Including the tax effected
impact of hedging on discounted future net cash flows would have increased
discounted future net cash flows by approximately $5.7 million as of December
31, 2001. Including the tax effected impact of hedging on discounted future
cash flows would have decreased discounted future net cash flows by
approximately $ 7.7 million and $35.7 million as of December 31, 2002 and 2000.
82
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required by this item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2002. 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, 2002. Such information is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Shareholder Matters
The information required by this item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2002. Such information is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required by this item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 2002. Such information is incorporated herein by reference.
Item 14. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Within 90 days prior to the filing date of this Form 10-K, 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. Based on those evaluations, the CEO and CFO believe:
i. that Mission's disclosure controls and procedures are designed to
ensure that information required to be disclosed by Mission in the reports
it files under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC's rules
and forms, and that such information is accumulated and communicated to
Mission's management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure; and
ii. that Mission's disclosure controls and procedures are effective.
Changes in Internal Controls
There have been no significant changes in Mission's internal controls or in
other factors that could significantly affect Mission's internal controls
subsequent to the evaluation referred to above, nor have there been any
corrective actions with regard to significant deficiencies or material
weaknesses.
83
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)
1. and 2. Financial Statements. See index to Consolidated Financial Statements and Supplemental
Information in Item 8, which information is incorporated herein by reference.
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.
3.5* Certificate of Amendment to Certificate of Incorporation of the Company.
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.
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 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).
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 Master Services Agreement dated October 1, 1999 between the Company and Torch Operating
Company, Torch Energy Marketing, Inc., Torch Energy Advisors, Inc. and Novistar, Inc.
(incorporated by reference to Exhibit 11.15 to the Company's Annual Report on Form 10-K filed
on March 24, 2000).
10.4 Credit Agreement dated May 16, 2001 among the Company as Borrower, The Chase Manhattan
Bank as administrative agent, BNP Paribas as syndication agent, First Union National Bank and
Fleet National Bank as co documentation agents (incorporated by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K filed on March 29, 2002).
84
10.5 First Amendment to the Credit Agreement by and among the Company and JPMorgan Chase
Bank, as Administrative Agent, BNP Paribas, as Syndication Agent, First Union National Bank
and Fleet National Bank, as Co-Documentation Agent, and the Lenders Signatory thereto, dated
May 29, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q filed August 14, 2002).
10.6 Second Amendment to the Credit Agreement by and among the Company and JPMorgan Chase
Bank, as Administrative Agent, BNP Paribas, as Syndication Agent, First Union National Bank
and Fleet National Bank, as Co-Documentation Agent, and the Lenders Signatory Hereto, dated
March 28, 2002 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on
Form 10-Q filed August 14, 2002).
10.7 Third Amendment to the Credit Agreement by and among the Company and JPMorgan Chase
Bank, as Administrative Agent, BNP Paribas, as Syndication Agent, Wachovia Bank National
Association and Fleet National Bank, as Co-Documentation Agent, and the Lenders Signatory
Hereto, dated October 7, 2002 (incorporated by reference to the Company's Current Report on
Form 8-K filed on October 10, 2002).
10.8 Employment Agreement effective as of May 15, 2000 between the Company and Douglas G.
Manner (incorporated by reference to Exhibit 10.20 to the Company's Quarterly Report on Form
10-Q filed August 11, 2000).
10.9 Separation Agreement between the Company and Douglas G. Manner dated effective July 31,
2002 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q
filed August 14, 2002).
10.10* Employment Agreement dated May 2, 2001, between the Company and Jonathan M. Clarkson.
10.11 Separation Agreement between the Company and Jonathon M. Clarkson effective September 30,
2002 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q
filed November 14, 2002).
10.12 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).
10.13 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).
10.14* Employment Agreement dated November 7, 2002, between the Company and John L. Eells.
10.15* Employment Agreement dated November 6, 2002, between the Company and Joseph G. Nicknish.
10.16* Employment Agreement dated May 15, 2001, between the Company and Daniel P. Foley.
10.17* Separation Agreement dated November 15, 2002, between the Company and Daniel P. Foley.
10.18 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).
21.1* Subsidiaries of the Company.
23.1* Consent of KPMG LLP.
23.2* Consent of Netherland Sewell & Associates, Inc.
23.3* Consent of Ryder Scott Company.
23.4* Consent of T.J. Smith & Company, Inc.
99.1* Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002, of the Chief Executive Officer of the Company.
99.2* Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002, of the Chief Financial Officer of the Company.
- --------
* Filed herewith.
85
(b) Reports on Form 8-K
(i) The Company filed a Current Report on Form 8-K on October 9, 2002, relating
to the resignation and hiring of new officers.
(ii) The Company filed a Current Report on Form 8-K on October 10, 2002,
relating to the amendment of its credit facility.
(iii) The Company filed a Current Report on Form 8-K on October 22, 2002,
relating to election of a board member.
(iv) The Company filed a Current Report on Form 8-K on November 14, 2002,
relating to third quarter 2002 results.
(v) The Company filed a Current Report on Form 8-K on November 25, 2002,
relating to the sale of non-strategic properties and the associated
borrowing base reduction.
(vi) The Company filed a Current Report on Form 8-K on December 19, 2002,
relating to first quarter 2003 guidance, year-end 2002 reserves estimates
and updates to current hedge position.
86
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.
. 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.
. MMBBL--One million Bbls of oil or other liquid hydrocarbons.
. MMCF--One million cubic feet of natural gas.
. MMBTU--One million British thermal units, a measurement of the energy
content of natural gas.
. MBOE--One thousand BOE.
. MMBOE--One million BOE.
Terms used to describe the Company's interests in wells and acreage
. Gross oil and gas wells or acres--Gross wells or gross acres represent
the total number of wells or acres in which Mission owns a working
interest.
. Net oil and gas wells or acres--Determined by multiplying "gross" oil and
natural gas wells or acres by the working interest that Mission owns in
such wells or acres represented by the underlying properties.
Terms used to assign a present value to the Company's reserves
. Standard measure of proved reserves--The present value, discounted at
10%, of the after-tax future net cash flows attributable to estimated net
proved reserves. We calculate this amount by assuming that we will sell
the oil and gas production attributable to the proved reserves estimated
in the independent engineer's reserve report for the prices we received
for the production on the date of the report, unless we had a contract to
sell the production for a different price. We also assume that the cost
to produce the reserves will remain constant at the costs prevailing on
the date of the report. The assumed costs are subtracted from the assumed
revenues resulting in a stream of future net cash flows. Estimated future
income taxes using rates in effect on the date of the report are deducted
from the net cash flow stream. The after-tax cash flows are discounted at
10% to result in the standardized measure of our proved reserves.
. Discounted present value--The discounted present value of proved reserves
is identical to the standardized measure, except that estimated future
income taxes are not deducted in calculating future net cash flows. We
disclose the discounted present value without deducting estimated income
taxes to provide what we believe is a better basis for comparison of our
reserves to other producers who may have different tax rates.
87
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
. Reserve life--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, 2002, 2001 or 2000 equals the estimated
net proved reserves attributable to a property or group of properties
divided by production from the property or group of properties for the
four fiscal quarters preceding the date as of which the proved reserves
were estimated.
Terms used to describe the legal ownership of our oil and gas properties
. Royalty interest--A real property interest entitling the owner to receive
a specified portion of the gross proceeds of the sale of oil and natural
gas production or, if the conveyance creating the interest provides, a
specific portion of oil and natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and natural gas.
A royalty interest owner has no 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.
88
. 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
geophones 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.
89
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
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
/S/ ROBERT L. CAVNAR
By:___________________________________
Robert L. Cavnar
Chairman and Chief Executive
Officer
Date: March 25, 2003
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.
Signatures Title Date
---------- ----- ----
/s/ Robert L. Cavnar Chairman and Chief Executive March 25, 2003
- ----------------------------- Officer (principal
Robert L. Cavnar executive officer)
/s/ RICHARD W. PIACENTI Senior Vice President and March 25, 2003
- ----------------------------- Chief Financial Officer
Richard W. Piacenti (principal financial
officer)
/s/ ANN KAESERMANN Vice President--Accounting March 25, 2003
- ----------------------------- and Investor Relations,
Ann Kaesermann Chief Accounting Officer
(principal accounting
officer)
/s/ JUDY LEY ALLEN Director March 25, 2003
- -----------------------------
Judy Ley Allen
/s/ DAVID A.B. BROWN Director March 25, 2003
- -----------------------------
David A.B. Brown
/s/ ROBERT R. ROONEY Director March 25, 2003
- -----------------------------
Robert R. Rooney
/s/ HERBERT C. WILLIAMSON Director March 25, 2003
- -----------------------------
Herbert C. Williamson
90
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
I, Robert L. Cavnar, certify that:
1. I have reviewed this annual report on Form 10-K of Mission Resources
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ ROBERT L. CAVNAR
--------------------------------------
Robert L. Cavnar
Chairman and Chief Executive Officer
91
MISSION RESOURCES CORPORATION AND SUBSIDIARIES
I, Richard W. Piacenti, certify that:
1. I have reviewed this annual report on Form 10-K of Mission Resources
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ RICHARD W. PIACENTI
--------------------------------------
Richard W. Piacenti
Senior Vice-President and Chief
Financial Officer
92