10-K405 1 d10k405.txt FORM 10-K FOR PERIOD ENDING DECEMBER 31, 2001 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 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, 2001 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, 77010 Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (713) 495-3000 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.01 par value NASDAQ/NMS 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 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the voting stock held by non-affiliates of the registrant at March 21, 2002 was approximately $72,167,829. As of March 21, 2002, the number of outstanding shares of the registrant's common stock was 23,585,632. Documents Incorporated by Reference: Portions of the registrant's annual proxy statement, to be filed within 120 days after December 31, 2001, are incorporated by reference into Part III. ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- MISSION RESOURCES CORPORATION AND SUBSIDIARIES Annual Report on Form 10-K For the Year Ended December 31, 2001 TABLE OF CONTENTS
Page Number ------ PART I Item 1. Business............................................................. 3 Item 2. Properties........................................................... 9 Item 3. Legal Proceedings.................................................... 19 Item 4. Submission of Matters to a Vote of Security Holders.................. 19 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters............................................................. 20 Item 6. Selected Financial Data.............................................. 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................... 22 Item 7a. Quantitative and Qualitative Disclosures About Market Risk........... 37 Item 8. Financial Statements and Supplementary Data.......................... 39 PART III Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................................ 79 Item 10. Directors and Executive Officers of the Registrant................... 79 Item 11. Executive Compensation............................................... 79 Item 12. Security Ownership of Certain Beneficial Owners and Management....... 79 Item 13. Certain Relationships and Related Transactions....................... 79 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...... 79 Signatures..................................................................... 86
2 MISSION RESOURCES CORPORATION AND SUBSIDIARIES PART I Item 1. Business 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 ("Exchange Act"). All statements other than statements of historical fact are forward-looking statements. Forward-looking statements are subject to risks and uncertainties and include information concerning future operations. Although we believe that in making such 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. Mission can give no assurances that the assumptions upon which these statements are based will prove to have been correct. Important factors that could cause actual results to differ materially from the expectations ("cautionary statements") are disclosed under Risk Factors and elsewhere herein. All subsequent written and oral forward-looking statements attributable to Mission or persons acting on its behalf are expressly qualified by the cautionary statements. General Mission Resources Corporation ("Mission" or the "Company") is an independent oil and gas exploration and production company. Mission acquires, develops and produces crude oil and natural gas primarily in the Permian Basin of West Texas, along the Texas and Louisiana Gulf Coast and in the Gulf of Mexico. At December 31, 2001, estimated net proved reserves, using constant prices which were in effect at such date, totaled 39 million barrels ("MMBBL") of oil, 2 MMBBL of natural gas liquids ("NGL"), and 154 billion cubic feet ("BCF") of natural gas for a total of 67 million barrels of oil equivalent ("MMBOE"). Approximately 62% of the estimated net proved reserves were oil or NGL, and approximately 75% of the reserves were developed. In order to facilitate greater comparability with its peer group by the financial community, Mission changed its fiscal year to the calendar year, beginning January 1, 1998. This resulted in a six-month transition period of July 1, 1997 through December 31, 1997. Business Strategy Mission's primary business objective is to create value through expanded reserves and production which, in turn, results in per-share increases in net asset value, cash flow and earnings. Mission pursues this goal using a combination of the following elements of our business strategy: . Create and pursue corporate mergers and acquisitions--We continually evaluate opportunities to acquire attractively priced reserves, through corporate transactions or property acquisitions. Targeted acquisitions improve the quality of our property portfolio, add significant exploitation and exploration potential, achieve economies of scale in operations, and improve our exposure in the financial markets. . Realize the value of core properties through exploitation and development--We seek to improve our success rates, reduce our finding and operating costs, and source prospects for development drilling by using an array of technologies, including 3-D seismic data, and reservoir stimulation modeling. Operationally, we use horizontal drilling, enhanced recovery methods and advanced completion and production techniques to be cost effective. These activities can increase production, cash flow and, in some cases, reserves. . Employ technical expertise to pursue growth through low- to moderate- risk exploration--Technology-driven interdisciplinary teams composed of geologists, geophysicists and engineers generate and evaluate exploration opportunities based on 3-D seismic evaluation, seismic processing and modeling 3 tools, and computer-aided exploration systems. Using this approach, we maximize the identification and quantification of opportunities and reduce risk through the application of complementary experience, know-how and technology. To limit our risk, we reduce our participation in certain exploratory prospects through sale of interests to industry partners. . Optimize base asset operations--To reduce and control operating costs, we regularly review our property base to identify non-core and lower margin assets. These assets are divested to allow redeployment of capital to expand more profitable operations or to reduce outstanding debt. At the same time, we expand operations through selective acquisitions within our core areas where we have proven technical and management expertise. . Maintain financial flexibility--Our operating objective is to keep capital spending within generated cash flow, and use free cash flow to repay bank debt. Periodically, we may refinance our bank debt when conditions are favorable. Given our acquisition strategy, debt levels will vary from time to time. Our long-term objectives are to limit debt levels to 50 percent of debt-to-book capitalization and maintain $100 million of unused bank capacity. We also use commodity price hedges, interest rate swaps and other financial strategies to reduce financial risks. 2001 Merger On May 16, 2001, Bellwether Exploration Company ("Bellwether") merged with Bargo Energy Company ("Bargo") and changed its name to Mission Resources Corporation. Simultaneously with the merger, Bellwether increased its authorized capital stock to 65.0 million shares and amended its 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. 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 new credit facility of $166.0 million used to refinance Bargo's and Bellwether's then existing credit facilities and to pay the cash portion of the purchase price of the Bargo common stock and options, and the amount incurred by Bargo to redeem 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 to reduce borrowings under the new credit facility. Oil and Gas Activities During 2000, after substantial analysis of its property portfolio in 1999, Mission divested several non-core properties. By December 31, 2000, Mission had sold approximately 6.4 MMBOE, or 17%, of its beginning of the year proved reserves, for gross proceeds of approximately $49.0 million. During 2001, Mission sold several non-core domestic oil and gas properties, its Ecuadorian interests, as discussed below, and its interests in the Snyder and Diamond M gas plants. Gross proceeds from these transactions totaled approximately $40.0 million. Approximately 14.3 MMBOE of proved reserves were sold. Approximately 8 MMBOE of sold reserves were burdened by $35.0 million in capital commitments. Ecuador In December 1998, Mission was the successful bidder for the Charapa field concession in Ecuador and, as a result, was awarded a contract for production and exploration of crude oil in the Charapa field. The contract provided Mission with approximately 45% of the crude oil produced above a base production curve defined by the hydrocarbon subsidiary of the Ecuadorian government. Mission was also entitled to recoup lease operating expenses associated with the base production. Mission took over operations of the field in January 2000. In February 2000, Mission took over operations of another Ecuadorian field, the Tiguino field. The contract with the government was similar for both fields. A Mission subsidiary operated the field on behalf of Petroleos Colombianos ("Petrocol"), which had been granted a 25% interest and operatorship by the Ecuadorian 4 government. Mission negotiated with Petrocol and other interest owners and by July 2000 had increased its interest to 70% and had been assigned the field operatorship. Final government approval of the transaction transferring ownership and operatorship in the Tiguino field was obtained in August 2001. Such approval was necessary for the agreements to be accepted in Ecuador. In June 2001, with an effective date of May 31, 2001, Mission entered into an agreement to sell its wholly owned subsidiaries, Bellwether International and Petrobell, to a Canadian company. Due to widening price differentials and higher operating costs, the economics of the Ecuador investment were no longer acceptable to Mission. The sale was contingent upon the receipt of final government approval of the Tiguino field transfer of ownership to Petrobell. These subsidiaries are party to the concessions of the Charapa and Tiguino fields in Ecuador. This transaction divested Mission of all interest in Ecuador, resulting in a net loss on the sale of $12.7 million and relieved it of approximately $35 million in capital spending commitments. Under the agreement, Mission retained two receivables: 1) a receivable of approximately $900,000 to be collected out of oil sales from the partner in the Tiguino field, and 2) a $1.0 million escrow receivable from the purchaser to be settled before year end upon resolution of negotiations with the Ecuadorian government concerning production levels. In the fourth quarter of 2001, management deemed the $1.0 million receivable to be uncollectible due to a lack of success in negotiating with the Ecuador government, increasing the loss on the sale to $12.7 million reported in 2001. Markets Mission's ability to market oil and gas from its wells depends upon numerous domestic and international factors beyond the Company's 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. No assurances can be given that Mission will be able to market all of the oil or gas it produces or that favorable prices can be obtained for the oil and gas Mission produces. Mission from time to time may enter into crude oil and natural gas price collars, swaps or other similar hedge transactions to reduce its exposure to price fluctuations. In view of the many uncertainties affecting the supply of and demand for oil, gas and refined petroleum products, Mission is unable to predict future oil and gas prices and demand or the overall effect such prices and demand will have on Mission. The marketing of oil and gas by Mission can be affected by a number of factors, which are beyond our control, the exact effects of which cannot be accurately predicted. Sales to Torch affiliates accounted for approximately 32%, 24% and 22% of fiscal year 2001, 2000 and 1999 oil and gas revenues, respectively. The contract with Torch was for an initial three-year term from December 1996, 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 are no other significant delivery commitments and substantially all of Mission's U.S. oil and gas production was sold at market responsive pricing by a marketing affiliate of Torch, as agent for Mission. Mission's Ecuadorian crude oil was sold to YPF and accounted for approximately 4% and 1% of the total company oil and gas revenue for 2000 and 2001, respectively. Commencing in early 2002, sales to Torch marketing affiliates are being replaced by sales to third parties. 5 Substantially all of Mission's oil and gas production will be sold at market responsive pricing. Mission carefully reviews the creditworthiness of those companies it chooses to contract with for oil or gas sales. Not only are financial statements reviewed and published credit ratings verified, but each company's overall reputation in the industry is considered. We do not believe that the loss of any single customer or contract would materially affect Mission's business. Regulation Federal Regulations Transportation of Gas--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 Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"), as well as under section 311 of the Natural Gas Policy Act ("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. 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 rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises 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 by Mission 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, the new 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 the Mission's operations. Federal, State or Indian Leases--In the event that Mission conducts operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM") or, in the case of the Company's Outer Continental Shelf ("OCS") leases in federal waters, Minerals Management Service ("MMS") or other appropriate federal or state agencies. Mission's outer continental shelf leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. Under certain circumstances, the MMS may require any company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. On March 15, 2000, the MMS issued a final rule effective June 2000, which amends 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 in the spot market 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. 6 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. Mission owns interests in numerous federal onshore oil and gas leases. It is possible that Mission 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 General--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 and . the prevention of waste of oil and gas resources. 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 it believes 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--Mission's activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Activities of Mission with respect to gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing gas and other products, are also 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 no assurance can be given that significant costs and liabilities will not be incurred in connection with environmental compliance issues. Mission also cannot 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 its operations could have on its activities. 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 Mission believes it has 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 owned or leased by Mission or on or under locations where such wastes have been taken for disposal. In addition, many of these properties are or have been owned or operated by third parties. Mission has had no control over such parties' 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 new laws, Mission 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. 7 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 Mission's oil and gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes" 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 certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances ("Hazardous Substances"). These classes of persons or so-called potentially responsible parties ("PRPs") include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances released at the site. CERCLA also authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts "petroleum" from the definition of Hazardous Substance, in the course of its operations, Mission has generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." Mission may also be an owner or operator of sites on which "hazardous substances" have been released. Mission may be responsible under CERCLA for all or part of the costs to investigate and remediation and natural resource damages at sites where hazardous substances have been released. Mission, to its knowledge has not been named a PRP under CERCLA nor does Mission know of any prior owners or operators of its properties that are named as PRPs related to their ownership or operation of such property. Clean Water Act--The Clean Water Act ("CWA") imposed 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. 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 federal waters. The CWA provides for civil, criminal and administrative penalties for 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 addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an authorized 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 liable "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 liable 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 a potential spill. Certain amendments to the OPA that were enacted in 1996 require 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 8 waters and $35 million in federal outer continental shelf ("OCS") waters, with higher amounts, up to $150 million based upon worst case oil spill discharge volume calculations. Mission believes that it currently has established adequate proof of financial responsibility for its 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, federally imposed requirements including additional permits. Particularly stringent requirements may be imposed on major sources located in areas designated as not meeting National Ambient Air Quality Standards established by the EPA. Some of Mission's facilities, particularly those along the Gulf Coast and in California, may be in non-attainment areas, but the specific location of these facilities is needed to make that determination. Federal and state laws designate to control hazardous (toxic) air pollutants, might require installation of additional controls. 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 could bring lawsuits for civil penalties or require Mission to forego construction, modification or operation of certain air emission sources. Coastal Coordination--There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act ("CZMA") was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. In Texas, the Texas Legislature enacted the Coastal Coordination Act in 1991 ("CCA"). The CCA provides for the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. The act establishes the Texas Coastal Management Program (CMP). The CMP is limited to the nineteen counties that border the Gulf of Mexico and its tidal bays. The act provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. This review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by Mission. OSHA and other Regulations--Mission is 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. Mission believes that it is in substantial compliance with these applicable requirements. Competition The oil and gas industry is highly competitive in all of its phases. Mission encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of reserves and producing properties and the marketing of oil and gas. Many of these companies possess greater financial and other resources than Mission. Competition for producing properties is affected by the amount of funds available to Mission, information about a producing property available to Mission and any standards established by Mission for the minimum projected return on investment. Competition may also be presented by alternate fuel sources. Item 2. Properties Domestic Properties Mission's domestic exploration, development and acquisition activities are focused in three core areas: along the Texas/Louisiana Gulf Coast, in the Permian Basin, and in the Gulf of Mexico. Mission primarily owns working interests in domestic wells. The owner of a working interest is required to pay its share of operating costs whereas the owner of royalty interests receives a share of revenues. 9 Reserve life is a measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. The reserve life index 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. The discounted present value is the present value, discounted at 10%, of the pre-tax future net cash flows attributable to estimated net proved reserves. This amount is calculated assuming the oil and gas production attributable to the proved reserves estimated in the independent engineer's reserve report using year end prices for production and assuming costs will remain constant. The assumed costs are subtracted from the assumed revenues, resulting in a stream of pre-tax future net cash flows. Gulf Coast--The fields in this area are located onshore in Louisiana and Texas. These fields produce gas as the primary product. Mission owns an interest in approximately 242 economically producing wells and the reserves from these wells account for about 53% of the discounted present value. Mission's average reserve life is 12 years. Mission's average working interest in the wells is approximately 35 percent. Permian Basin--The fields in this area are located in West Texas and New Mexico. The West Texas fields produce oil and the New Mexico fields produce gas as the primary product. Mission owns an interest in approximately 3,223 economically producing wells and the reserves from these wells account for about 29% of the discounted present value. Mission's average reserve life is 13 years. Mission's average working interest in the wells is approximately 11 percent. Gulf of Mexico--The fields in this area are located in state and federal waters offshore Louisiana and Texas. These fields produce gas as the primary product. Mission owns an interest in approximately 92 economically producing wells and the reserves from these wells account for about 8% of the discounted present value. Mission's average reserve life is 3 years. Mission's average working interest in the wells is approximately 20 percent. Other--Non-core fields are located primarily in California, Oregon, Oklahoma, East Texas and Wyoming. Mission owns an interest in approximately 375 economically producing wells and the reserves from these wells account for about 10% of the discounted present value. International Properties Ecuador--Mission operated two concessions in Ecuador, each of which contained one producing field. The working interest in the Charapa field was 90% and the working interest in the Tiguino field was 70%. Oil was the only sales product from both fields. Both fields were subject to contracts with the Ecuador government, under which Mission had a share of production above specified base levels. In June 2001 the interests in Ecuador properties were sold; therefore, no Ecuadorian reserves are reported as of December 31, 2001. Reserves Estimated net proved oil and gas reserves at December 31, 2001 increased approximately 113% from December 31, 2000. Reserves of approximately 43 MMBOE were added as a result of the May 2001 merger, and approximately 8 MMBOE were added as a result of property acquisitions. Properties, with proved reserves totaling 12 MMBOE, were sold during 2001. The Company has not filed oil or gas reserve information with any foreign government or federal authority or agency that contain reserves materially different than those presented herein. 10 The following table sets forth certain information as of December 31, 2001 for Mission's core areas (dollars in thousands).
Estimated Net Proved Net Production(1) Reserves ------------------------- -------------------------- Discounted Oil & Oil Oil & Oil Future Net NGL Gas Equivalent NGL Gas Equivalent Cash Area (MBBLS) (MMCF) (MBOE) (MBBLS) (MMCF) (MBOE) Flows(3) ---- ------- ------ ---------- ------- ------- ---------- ---------- Gulf Coast.............. 607 6,139 1,630 8,763 95,675 24,709 $194,615 Gulf of Mexico.......... 528 8,184 1,892 1,602 20,611 5,037 27,331 Permian Basin........... 1,220 1,919 1,540 23,375 25,523 27,628 107,519 Other(2)................ 1,043 1,355 1,269 7,858 12,273 9,904 35,969 ----- ------ ----- ------ ------- ------ -------- 3,398 17,597 6,331 41,598 154,082 67,278 $365,434 ===== ====== ===== ====== ======= ====== ========
-------- (1) Net production includes operations from the fields acquired from Bargo beginning May 16, 2001. (2) Properties located in East Texas are included in this category. (3) Future cash flows discounted at 10 percent. 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 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 ("SEC"), the estimated 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. Additionally, the impact of financial derivatives is not considered. 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. Acreage The following table sets forth the developed and undeveloped oil and gas acreage in which Mission held an interest as of December 31, 2001. 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 Mission owns a working interest. The number of net acres is the sum of the fractional ownership of working interests Mission owns 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 Mission's developed and undeveloped acreage is domestic. 11
Gross Net --------- ------- Developed Acreage: Gulf Coast............................................... 92,246 30,994 Gulf of Mexico........................................... 182,291 35,181 Permian Basin............................................ 206,448 37,721 Other.................................................... 76,751 20,536 --------- ------- Total Developed Acreage................................ 557,736 124,432 --------- ------- Undeveloped Acreage: Gulf Coast............................................... 25,693 12,588 Gulf of Mexico........................................... 52,785 17,935 Permian Basin............................................ 914,961 306,803 Other.................................................... 72,819 31,485 --------- ------- Total Undeveloped Acreage.............................. 1,066,258 368,811 --------- ------- Total Company Acreage.................................. 1,623,994 493,243 ========= =======
Mission believes title to its oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in its opinion, are not so material as to detract substantially from the use or value of such properties. Mission's 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 Mission's rights to production revenues, they have been taken into account in calculating net revenue interests and in estimating the size and value of Mission's reserves. Mission believes that the burdens and obligations affecting its properties are conventional in the industry for properties of the kind owned by Mission. See "Risk Factors" for a discussion of estimates of oil and gas reserves. Productive Wells The following table sets forth Mission 's gross and net interests in productive oil and gas wells as of December 31, 2001. Productive wells are defined as producing wells and wells capable of production. Gross wells, as it applies to wells in the following tables, refer to the number of wells in which Mission owned a working interest. A "net well" is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional ownership of working interests owned directly by Mission in gross wells. 12
Gross Net ----- ----- Oil Wells: Gulf Coast..................................................... 188 114 Gulf of Mexico................................................. 74 12 Permian Basin.................................................. 1,067 179 Other.......................................................... 384 224 ----- ----- Total Oil Wells.............................................. 1,713 529 ----- ----- Gas Wells: Gulf Coast..................................................... 183 62 Gulf of Mexico................................................. 217 32 Permian Basin.................................................. 2,422 464 Other.......................................................... 181 31 ----- ----- Total Gas Wells.............................................. 3,003 589 ----- ----- Total Wells.................................................. 4,716 1,118 ===== =====
Production Mission's principal production volumes during the fiscal year ended December 31, 2001 were from the states of Louisiana, Texas, and New Mexico, from federal waters offshore California and from federal and state waters in the Gulf of Mexico. Because they were sold June 1, 2001, the Charapa and Tiguino fields in Ecuador accounted for only about 2.8 % of total 2001 oil production. Data relating to production volumes, average sales prices, average unit production costs and oil and gas reserve information appears in Note 13 of the Notes to Consolidated Financial Statements--Supplemental Information. Drilling Activity and Present Activities During the last three fiscal years the Company's principal domestic drilling activities occurred along the Texas and Louisiana Gulf Coast, in the Gulf of Mexico, Oregon and New Mexico. Development of the Charapa and Tiguino fields in Ecuador accounted for all international 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 ---------- ----- ----- ---------- ----- ----- 1999--Domestic................. 8 4 12 3.75 2.04 5.79 2000--Domestic................. 7 6 13 3.98 1.96 5.94 2000--Ecuador.................. -- -- -- -- -- -- 2001--Domestic................. 2 6 8 0.92 1.13 2.05 Development Wells Gross Net ---------------------- ---------------------- Dry Dry Productive Holes Total Productive Holes Total ---------- ----- ----- ---------- ----- ----- 1999--Domestic................. 13 2 15 4.39 0.14 4.53 2000--Domestic................. 46 8 54 15.01 2.70 17.71 2000--Ecuador.................. 1 3 4 0.07 2.70 3.40 2001--Domestic................. 48 7 55 14.24 5.13 19.37
Six domestic wells were in progress as of December 31, 2001. 13 Gas Plants In late 2001, Mission sold its 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. Mission's 19.7% interest in this plant is no longer reported 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. Risk Factors Volatility of Oil and Gas Prices and Markets 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 Mission's 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, . 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 Mission's proved reserves, its borrowing capacity, its ability to obtain additional capital, and its revenues, profitability and cash flows. 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. The availability of a ready market for oil and natural gas production also depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to, and the capacity of, oil and natural gas gathering systems, pipelines or trucking and terminal facilities. Wells may temporarily be shut-in for lack of a market or due to inadequacy or unavailability of pipeline or gathering system capacity. Ability to Replace Reserves Mission's future performance depends upon its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. The proved reserves of Mission will generally decline as those reserves are depleted. Mission therefore must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. No assurances can be given that Mission will be able to find and develop or acquire additional reserves at an acceptable cost. Acquisition Risks The rapid growth of Mission and its predecessor companies in recent years has been attributable in significant part to domestic acquisitions of oil and gas properties. Mission expects to continue to evaluate and, 14 where appropriate, pursue acquisition opportunities on terms management considers favorable to Mission. There can be no assurance that suitable acquisition candidates will be identified in the future, or that Mission will be able to finance such acquisitions on favorable terms. In addition, Mission competes against other companies for acquisitions, and there can be no assurances that it will be successful in the acquisition of any material property interests. Further, there can be no assurances that any future acquisitions made by Mission will be integrated successfully into its operations or will achieve desired profitability objectives. The successful acquisition of producing properties requires an assessment of: . recoverable reserves, . future production rates, . exploration and exploitation potential and timing, . future oil and natural gas prices, . operating costs, . infrastructure requirements, . potential environmental and other liabilities and . other factors beyond our control. In connection with such an assessment, Mission will perform a review of the properties that it believes to be generally consistent with industry practices. Nonetheless, the resulting assessments are inexact and their accuracy is inherently uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit Mission to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. In addition, sellers of properties may be unwilling or financially unable to indemnify Mission for known or unknown liabilities at the time of an acquisition. Additionally, significant acquisitions can change the nature of the operations and business of Mission depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics and geographic location from existing properties. While Mission's operations are focused in Texas, Louisiana, New Mexico and the Gulf of Mexico, there is no assurance that Mission will not pursue acquisitions or properties located in other geographic areas. Drilling Risks Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by Mission will be productive or that Mission will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. Mission's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond its control, including: . title problems, . weather conditions, . compliance with governmental requirements, . shortages or delays in the delivery of equipment and services, and . drilling and operations difficulties. 15 Substantial Capital Requirements Mission makes, and will continue to make, substantial capital expenditures for the exploitation, exploration, acquisition and production of oil and gas reserves. Historically, Mission has financed these expenditures primarily with the sale of senior subordinated notes, proceeds from bank borrowings, sales of its common stock and cash flow from operations. We believe that Mission will have sufficient cash flow provided by operating activities, the proceeds of equity and debt offerings and borrowings under bank debt to fund planned capital expenditures. If revenues or Mission's borrowing base decrease as a result of lower oil and gas prices, operating difficulties or declines in reserves, Mission may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements. Significant Leverage and Debt Service Mission's level of indebtedness has several important effects on its future operations, including: . a substantial portion of Mission's cash flow from operations must be dedicated to the payment of interest on its indebtedness and will not be available for other purposes, . covenants contained in Mission's debt obligations require Mission to meet certain financial tests, and other restrictions limit its ability to borrow additional funds or dispose of assets and may affect Mission's flexibility in planning for, and reacting to, changes in its business, including possible acquisition activities, and . Mission's ability to obtain financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. Mission's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon future performance, which will be subject to general economic conditions and to financial, business and other factors affecting the operations of Mission, many of which are beyond its control. There can be no assurance that Mission's future performance will not be adversely affected by such economic conditions and financial, business and other factors. Outsourcing Agreement Mission currently has 27 employees. Mission is party to a Master Service Agreement ("MSA") dated October 1, 1999, and four specific contracts which required Torch and its subsidiaries to administer certain of Mission's activities including oil and gas marketing, operation of oil and gas properties, accounting, risk management, legal and information technology. At the end of 2001 the Company gave notice to Torch that the agreements covering accounting, risk management, legal, information technology and operation of oil and gas properties would be cancelled or allowed to expire in 2002. We believe that the experienced professional, technical and administrative personnel and the access to suitable accounting and reporting systems necessary for Mission to operate effectively can be obtained elsewhere. Conflicts of Interest Related to Outsourcing Mr. J. P. Bryan served as Chief Executive Officer of Bellwether from August 1999 through May 2000. He continues to be a member of the Mission board of directors. Mr. Bryan is also Senior Managing Director of Torch and owns shares representing 23% of the shares of Torch on a fully diluted basis. Mr. Bryan also owned 1,061,750 shares of Bargo before the merger. Mr. Tim Goff, former Chairman of Bargo and current member of Mission's board of directors, is a non-compensated advisor to Torch regarding potential oil and gas property acquisitions. As discussed above, Torch and subsidiaries provide outsourcing services to Mission. Torch and subsidiaries render outsourcing services to other independent oil and gas companies and may manage or render management or administrative services for other energy companies in the future. These services 16 may include the review and recommendation of potential acquisitions. It is possible that conflicts may occur between Mission and these other companies in connection with possible acquisitions or otherwise in connection with the services rendered by Torch. Although the MSA provides for procedures to reconcile conflicts of interest between these other companies and Mission, no assurances can be made that such procedures will fully protect Mission from losses which may occur if a conflict between it and these other companies arises. Estimates of Oil and Gas Reserves This document contains estimates of oil and gas reserves owned by Mission, 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 the control of Mission and the 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 set forth herein. 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 an 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 Mission on the sale of its oil and gas production. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to estimated proved reserves set forth herein were prepared in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. Hedging of Production Mission may, from time to time, reduce its exposure to the volatility of oil and gas prices by hedging a portion of its production. In a typical hedge transaction, Mission will have the right to receive from the counterparty 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, Mission is required to pay the counterparty this difference multiplied by the quantity hedged. In such case, Mission is required to pay the difference regardless of whether it 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 Mission to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent Mission from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. Operating Hazards, Offshore Operations and Uninsured Risks Mission's operations are subject to risks inherent in the oil and gas industry, such as: . blowouts, . cratering, . explosions, 17 . uncontrollable flows of oil, gas or well fluids, . fires, . pollution, . earthquakes and . environmental risks. These risks could result in substantial losses to Mission 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 Mission's operations are offshore and therefore are subject to a variety of operating risks which occur in to 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. Mission's 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 Mission could 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 Mission's financial condition and results of operations. Mission maintains insurance coverage for its operations, including limited coverage for sudden environmental damages, but does 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, Mission may be subject to liability or the loss of substantial portions of its properties in the event of certain environmental damages. Environmental and Other Regulation Mission's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. 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 . impose substantial liabilities for pollution resulting from the Company's operations Moreover, the recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes" which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on Mission's operating costs, as well as the oil and gas industry in 18 general. Initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on Mission. 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 Mission. Competition The oil and gas business is highly competitive. Many competitors have substantially larger financial resources, staffs and facilities than Mission. These larger competitors include independent oil and gas producers such as Apache Corporation, Burlington Resources, Inc., Anadarko Petroleum Inc., and Ocean Energy, Inc. The availability of funds and information relating to a property, the standards established by Mission for the minimum projected return on investment, the availability of alternate fuel sources and the intermediate transportation of oil and gas are factors which affect Mission's ability to compete in the marketplace. Item 3. Legal Proceedings Mission has been named as a defendant in certain lawsuits incidental to its own business. Management does not believe that the outcome of such litigation will have a material adverse impact on Mission. Item 4. Submission of Matters to a Vote of Security Holders None. 19 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters Mission's common stock is traded on the NASDAQ National Market (Symbol: MSSN). There were approximately 721 stockholders of record as of March 21, 2002. Mission has not paid dividends on its common stock and does not anticipate the payment of cash dividends in the immediate future as it contemplates that cash flows will be used for continued growth of our operations. In addition, certain covenants contained in Mission's financing arrangements restrict the payment of dividends (see Management's Discussion and Analysis of Financial Condition and Results of Operations--Financing Activities and Note 7 of the Notes to Consolidated Financial Statements). The following table sets forth the range of the high and low sales prices, as reported by the NASDAQ for Mission common stock for the periods indicated.
Sales Price ----------- High Low ----- ----- Quarter Ended: March 31, 1999................................................. $5.56 $2.69 June 30, 1999.................................................. $5.75 $3.19 September 30, 1999............................................. $6.25 $4.00 December 31, 1999.............................................. $6.19 $3.88 March 31, 2000................................................. $7.25 $4.19 June 30, 2000.................................................. $9.88 $5.63 September 30, 2000............................................. $8.88 $6.69 December 31, 2000.............................................. $8.50 $5.88 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
Treasury Stock Repurchases In September 1998, the board of directors authorized the open market repurchase of up to $5.0 million of Bellwether, now Mission, common stock during 1998, at times and prices deemed attractive by management. As of December 31, 2001, we had repurchased 311,000 shares of common stock in open market transactions at an average purchase price of $6.13 per share. No shares were purchased in 1999, 2000 or 2001. 20 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).
Six Month Transition Fiscal Year Year Year Year Period Year Ended Ended Ended Ended Ended Ended Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, June. 30, 2001(2) 2000 1999 1998 1997 1997(1) -------- -------- -------- -------- ---------- --------- Gas revenues............ $ 57,705 $ 62,652 $ 41,559 $ 46,661 $ 26,849 $ 24,323 Oil revenues............ 75,530 49,601 26,705 26,991 17,519 15,006 Gas plant revenues...... 4,456 6,070 3,830 3,170 2,036 6,652 Interest and other income................. 4,386 957 1,335 1,347 609 363 -------- -------- -------- -------- -------- -------- Total revenues........ $142,077 $ 19,280 $ 73,429 $ 78,169 $ 47,013 $ 46,344 Production expenses..... 51,205 30,509 21,532 25,381 13,836 11,437 Transportation costs.... 73 270 316 435 205 262 Gas plant expenses...... 2,118 2,677 2,366 1,967 1,232 3,322 Depreciation, depletion and Amortization....... 45,106 32,654 23,863 39,688 16,352 15,574 Impairment expense...... 27,057 -- -- 73,899 -- -- Disposition of hedges... -- 8,671 -- -- -- -- Uncollectible gas revenues............... 2,189 -- -- -- -- -- Mining venture costs.... 914 -- -- -- -- -- Loss on sale of assets.. 11,600 -- -- -- -- -- General and administrative Expenses............... 15,384 9,138 7,848 8,459 3,748 4,042 Interest expense........ 23,664 15,375 11,845 11,660 5,978 4,477 Provision for income tax (benefit).............. (9,055) (12,222) (3,154) (6,069) 2,114 2,585 -------- -------- -------- -------- -------- -------- Total expenses........ 170,255 87,072 64,616 155,420 43,465 41,699 Cumulative effect of a change in accounting method, net of deferred taxes.................. 2,767 -- -- -- -- -- -------- -------- -------- -------- -------- -------- Net income (loss)....... $(30,945) $ 32,208 $ 8,813 $(77,251) $ 3,548 $ 4,645 ======== ======== ======== ======== ======== ======== Earnings (loss) per common share........... $ (1.54) $ 2.32 $ 0.64 $ (5.50) $ 0.26 $ 0.46 Earnings (loss) per common share--diluted.. $ (1.54) $ 2.27 $ 0.63 $ (5.50) $ 0.25 $ 0.45 Working capital......... $ 105 $ 7,212 $ 3,770 $ 6,077 $ 13,964 $ 22,783 Long-term debt, net of current Maturities(3).. $261,695 $125,450 $130,000 $104,400 $100,000 $115,300 Stockholders' equity.... $110,240 $ 56,960 $ 23,314 $ 14,489 $ 91,669 $ 87,924 Total assets............ $447,764 $221,545 $171,761 $131,196 $214,757 $222,648
-------- (1) Includes operations from the Partnership Transactions beginning April 1, 1997. (2) Includes operations of Bargo properties beginning May 16, 2001. (3) Includes, at December 31, 2001, a $1.8 million, unamortized premium on the $125 million of bonds issued May 2001. 21 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. 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 acquisitions, property enhancement through exploitation and development drilling, low- to moderate-risk exploration, asset redeployment and operating cost reduction. Mission's primary business objective is to create value through expanded reserves and production which, in turn, results in per-share increases in net asset value, cash flow and earnings. On May 16, 2001, Bellwether Exploration Company merged with Bargo Energy Company and changed its name to Mission Resources Corporation. Contemporaneously with the merger, Bellwether increased its authorized capital stock to 65.0 million shares and amended its 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. The merger was financed through the issuance of $80.0 million in 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 to pay the cash portion of the purchase price paid 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. Mission issued $125.0 million of additional subordinated notes on May 29, 2001 and used most of the proceeds to reduce borrowings under the Credit Facility. Financing Activities Mission's outstanding indebtedness totaled $260.0 million at December 31, 2001 with $225.0 million attributable to the 10 7/8% Senior Subordinated Notes due in 2007 and $35.0 million outstanding under a $200.0 million senior revolving credit facility with a three-year term. Mission acquired producing properties (other than the Bargo merger) for $23.4 million during 2001, primarily using borrowings under its Credit Facility Mission is party to a $200.0 million credit facility with a syndicate of lenders. The Credit Facility is a revolving facility, 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, 2001, Mission's borrowing base was $125.0 million. 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 (1) the prime rate, as determined by Chase Manhattan Bank, or (2) 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 (1) the utilization rate as a percentage of the total amount of funds borrowed under the Credit Facility to the borrowing base and (2) 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. The Credit Facility contains negative covenants that limit Mission's ability, among other things, to: . incur additional debt; 22 . 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: . an interest coverage ratio of earnings before interest, depreciation, depletion, amortization, income tax, and extraordinary items, or EBITDAX, to net interest expense of at least 2.5 to 1.0; . an asset coverage or current ratio (which includes availability) of at least 1.0 to 1.0; and . a ratio of total debt to EBITDAX of no more than 3.5 to 1.0. On December 31, 2001, the Company had outstanding borrowings of $35.0 million and was in compliance with its covenants under the Credit Facility. Mission met with its lenders on March 5, 2002 to discuss the re- determination of the borrowing base applicable to the Credit Facility and effective April 1, 2002 the borrowing base is $100.0 million. Mission also requested amendments to its debt covenants in response to the late 2001 and early 2002 decline in prices and their potential impact on 2002 forecast financial results. Mission's debt covenants for the four quarters of 2002 were amended with the required ratio of total debt to EBITDAX being increased and the required interest coverage ratio being reduced. Currently, Mission expects to be in compliance with such amended covenants in 2002. Borrowings at March 15, 2001, were $45.5 million outstanding under the Credit Facility, but are expected to be reduced by March 31, 2002 due to proceeds from property sales. In April 1997, Mission entered into a senior revolving credit facility ("Senior Credit Facility") in an amount up to $90.0 million, with a borrowing base of $55.0 million, and a maturity date of November 5, 2003. This Senior Credit Facility was terminated in favor of the Credit Facility established in conjunction with the May 16, 2001 merger with Bargo. In April 1997, Mission issued $100.0 million of 10 7/8% senior subordinated notes that mature April 1, 2007. Interest is payable semi-annually on April 1 and October 1. The 10 7/8% senior subordinated notes contain certain covenants, including limitations on: . incurrence of debt, . other senior subordinated indebtedness, . restricted payments, . liens as well as restrictions . disposition of proceeds of asset sales, . mergers, and . consolidations or sales of assets. 23 Additionally, they require Mission to offer to purchase the 10 7/8% senior subordinated notes in the event of a change of control, as defined in the indenture. In May 2001, Mission issued $125.0 million of additional 10 7/8% senior subordinated notes due 2007 in a private offering and used most of the proceeds to reduce borrowings under the Credit Facility. These senior subordinated notes had terms substantially identical to Mission's senior subordinated notes due 2007 issued in April 1997. On July 27, 2001 Mission filed a registration statement on Form S-4 to exchange $225.0 million of senior subordinated notes due 2007 issued in 1997 and 2001 for $225.0 million of a new series of registered senior subordinated notes that have substantially identical terms to the exchanged notes. That exchange was completed in August 2001. Effective September 22, 1998, Mission entered into an eight and one-half year interest rate swap agreement with a notional value of $80 million. Under the agreement, Mission receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are re-determined for a six-month period each April 1 and October 1. Through April 1, 2002, the floating rate is capped at 10.875% and capped at 12.375% thereafter. The floating rate for the period from October 1, 2001 to April 1, 2002 is 9.87%. Beginning January 1, 2001, pursuant to SFAS No. 133, the swap does not qualify for hedge accounting. Changes in its fair value are recognized each period as a non-cash component of interest expense. Liquidity and Capital Resources Mission's principal sources of capital for the last three years have been the issuance of common stock, the sales of non-core properties, debt sources such as the issuance of bonds or bank credit facility borrowings, and cash flow from operations. Mission's primary uses of capital have been the funding of acquisitions and the funding of its exploration and development projects. Source of Capital: Issuance of Common Stock Mission 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, authorized capital stock was increased to 65.0 million shares. Source of Capital: Sale of Properties Divestitures of non-core domestic oil and gas properties in the years 2001 and 2000 realized proceeds, after adjustment for transaction costs and interim operations, of approximately $15.9 million and $46.0 million, respectively. Additionally, the sale of Mission's Ecuadorian interests in June 2001 netted approximately $4.8 million and the sale of Mission's interests in the Snyder and Diamond M gas plants netted approximately $10.9 million. A majority of the sales proceeds were used to pay down borrowings outstanding under the Credit Facility. Mission intends to divest of additional non-core oil and gas properties in the first quarter of 2002 for approximately $10.0 to $15.0 million and use the proceeds to pay down borrowings under the Credit Facility. Although Mission believes it will be able to generate the desired amount of cash from these divestitures, it is possible that market conditions could result in the properties being sold for more or less than originally believed. Should the divestitures fail to generate the desired amount of cash, Mission may be required to locate other sources of funds, which could include but are not limited to, the sale of additional properties or additional borrowings under its credit facility. Source of Capital: Debt Mission's outstanding balance under its 10 7/8% senior subordinated notes was $225.0 million at December 31, 2001 and was $100.0 million at the end of both 2000 and 1999. Borrowings from banks under Mission's revolving credit facility were $35.0 million, $25.5 million, and $30.0 million at the end of fiscal years 24 2001, 2000, and 1999, respectively. At December 31, 2001, available debt capacity under the Credit Facility, was $90.0 million. As previously discussed under "Financing Activities", both Mission's senior subordinated notes and its credit facility have certain covenants limiting Mission's activities or requiring specific financial ratios. As of December 31, 2001, Mission was in compliance with all the covenants. For 2002, Mission has requested and its banks have agreed to amend the financial ratio requirements. Mission expects to be able to meet such amended requirements. If commodity prices were to continue declining and Mission were unable to meet these amended requirements, then Mission would negotiate additional amendments with the banks or obtain a temporary waiver of the covenants from the banks. Should the banks fail to approve such actions, then Mission would obtain the funds to repay the outstanding credit facility debt through property sales or equity financing. Mission receives debt ratings from two major rating agencies in the United States. In determining Mission's debt rating, the agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term production growth opportunities, capital allocation challenges and commodity price levels. Mission's corporate ratings are "B+" by Standard & Poor's and "B1" by Moody's. Standard & Poor's and Moody's have put Mission on Credit Watch--negative and on review for downgrade respectively, in March 2002. There are no "rating triggers" in any of Mission's contractual obligations that would accelerate scheduled maturities should Mission's debt ratings fall below a specified level. Source of Capital: Operations Cash flow from operations before changes in assets and liabilities ("operating cash flow") totaled $44.7 million, $62.6 million, and $30.8 million for the fiscal years 2001, 2000, and 1999, respectively. Mission's operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGL produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic growth, weather and other variable factors influence market conditions for these products. These factors are beyond Mission's control and are difficult to predict. To mitigate some of the risk inherent in oil and natural gas prices, Mission has entered into various price collars to set minimum and maximum prices on a portion of its production. Mission's policy is to hedge price risk on up to 70% of its production through such instruments. Currently, Mission has hedged forecast production under the various arrangements shown on the tables below. Oil Hedges
BBLS NYMEX NYMEX Per Total Price Price Period Day BBLS Type Floor Ceiling ------ ----- ------- ------ ------ ------- Jan. 2002-Mar. 2002...................... 6,000 540,000 Collar $21.50 $31.25 Apr. 2002-June 2002...................... 5,400 491,400 Collar $21.50 $30.25 Apr. 2002-June 2002...................... 500 45,500 Collar $21.00 $26.25 Apr. 2002-June 2002...................... 500 45,500 Collar $26.00 $25.05 July 2002-Sep. 2002...................... 4,700 432,400 Collar $21.50 $28.45 July 2002-Sep. 2002...................... 500 46,000 Collar $21.00 $25.03 July 2002-Sep. 2002...................... 500 46,000 Collar $21.00 $26.00 Oct. 2002-Dec. 2002...................... 4,000 368,000 Collar $21.50 $27.15 Oct. 2002-Dec. 2002...................... 500 46,000 Collar $21.00 $25.01 Oct. 2002-Dec. 2002...................... 500 46,000 Collar $21.00 $25.25 Jan. 2003-Mar. 2003...................... 2,500 225,000 Collar $20.50 $24.11 Jan. 2003-Mar.2003....................... 500 45,000 Collar $21.00 $25.00 Apr. 2003-June 2003...................... 2,500 227,500 Collar $20.50 $24.08 Apr. 2003-June 2003...................... 500 45,500 Collar $21.00 $24.65 July 2003-Sep. 2003...................... 2,500 230,000 Collar $20.50 $24.05 July 2003-Sep. 2003...................... 500 46,000 Collar $20.50 $24.50 Oct. 2003-Dec. 2003...................... 2,500 230,000 Collar $20.50 $24.02 Oct. 2003-Dec. 2003...................... 500 46,000 Collar $20.50 $24.25
25 Gas Hedges
MCF NYMEX NYMEX Per Price Price Period day Total MCF Type Floro Ceiling ------ ------ --------- ------ ----- ------- Jan. 2002-Mar. 2002.................... 11,700 1,053,000 Collar $3.57 $7.00 Apr. 2002-June 2002.................... 10,200 928,200 Collar $3.00 $6.48 July 2002-Sep. 2002.................... 9,800 901,600 Collar $3.00 $6.60 July 2002-Sep. 2002.................... 10,000 920,000 Collar $2.50 $3.55 Oct. 2002-Dec. 2002.................... 8,500 782,000 Collar $3.40 $7.00 Jan. 2003-Mar. 2003.................... 10,000 900,000 Collar $3.00 $4.65 Apr. 2003-June 2003.................... 5,000 455,000 Collar $3.00 $4.02 Apr. 2003-June 2003.................... 5,000 455,000 Collar $3.00 $3.97 July 2003-Sep. 2003.................... 10,000 920,000 Collar $3.00 $4.10 Oct. 2003-Nov. 2003.................... 10,000 920,000 Collar $3.00 $4.65
By removing the price volatility from these volumes of oil and natural gas production, Mission has mitigated, but not eliminated, the potential negative effect of declining prices on its operating cash flow. The potential for increased operating cash flow due to increasing prices has also been capped. Immediate settlement of the Company's commodity hedges would have increased future cash flows by $6.1 million at December 31, 2001; however the actual settlement of such hedges will increase or decrease cash flows over the period of the hedges. It is Mission's policy to only enter into derivative contracts with investment grade rated counterparties deemed by management as competent and competitive market makers. Use of Capital: Acquisitions The merger with Bargo, valued at $280.9 million, was the most significant acquisition of 2001. Other domestic property acquisitions totaled $23.5 million, $7.1 million and $25.9 million for the years 2001, 2000 and 1999, respectively. Spending related to the acquisition of the Tiguino field in Ecuador totaled approximately $249,000 and $2.0 million in the years 2001 and 2000, respectively. Mission is continuously reviewing acquisition opportunities. Future acquisitions would be funded through additional borrowings under the Credit Facility or the issuance of equity securities. Use of Capital: Exploration and Development Mission's expenditures for exploration, including land and seismic costs, and development of its oil and gas properties totaled $49.4 million, $81.3 million and $30.9 million, for the fiscal years 2001, 2000, and 1999, respectively. Development activities in Ecuador accounted for approximately $3.9 million and $10.0 million of expenditures in the years 2001 and 2000, respectively. In December, Mission announced a capital budget for 2002 totaling $33.3 million, with $10.2 million for exploration, $14.3 million for domestic development, and $8.8 million for seismic data, land and related items. Mission believes its working capital and operating cash flow will be sufficient to meet the exploration and development plans detailed in the budget. This capital budget represents the largest planned use of available operating cash flow. To a certain degree, the ultimate timing of these capital expenditures is within Mission's control. Therefore, if oil and gas prices decline to levels below its acceptable levels, Mission will choose to defer a portion of these planned 2002 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. In February 2002, Mission announced that the capital budget for 2002 would be reduced to $27.0 million due to oil and gas price declines. 26 Critical Accounting Policies In December 2001, the Securities and Exchange Commission encouraged public companies to include in their annual report information on critical accounting policies. These policies have been defined as those that are very important to the portrayal of the company's financial condition or results of operations, and require management's most difficult, subjective or complex judgements. Full Cost Method of Accounting for Oil and Gas Assets Mission uses the full cost method of accounting for its investment 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 in a "full cost pool" as incurred. In accordance with the full cost method, included in the capitalized full costs pool are a portion of certain employee-related costs incurred for the purpose of finding and developing oil and gas reserves. Employee-related costs which are directly attributable to exploration and development are capitalized based on analysis of time spent on these activities. Amounts capitalized can be significant with increasing exploration and major development activities particularly in deep waters. Oil and gas properties in the pool, plus estimated future expenditures to develop proved reserves and future abandonment, site reclamation and dismantlement costs, are depleted and charged to operations using the unit of production method based on the ratio of current production to total proved recoverable oil and gas reserves. The full cost method subjects companies to a quarterly calculation of a "ceiling" or limitation on the amount that may be capitalized on the balance sheet related to oil and gas properties. To the extent that capitalized costs (net of depreciation, depletion and amortization) exceed the calculated ceiling, the excess must be written off to expense. Once incurred, the writedown of oil and gas properties is not reversible at a later date even if oil and gas prices increase. Mission's discounted present value of its proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgements. Estimates of reserves are forecasts based on engineering data, projected future rates of production, and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgement, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Mission's reserve estimates are prepared by outside consultants. The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. If future significant downward revisions reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of these estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A. While quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves do not require judgment. 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 such prices and costs in effect as of the end of each quarter when the ceiling calculation is performed. In calculating the ceiling, Mission adjusts the end-of-period price by the effect of cash flow hedges in place. Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been variable and, on any particular day at the end of a quarter, can be either substantially higher or lower than Mission's long-term price forecast more indicative of true fair value. Oil and gas property writedowns resulting from the application of the full cost ceiling limitation, and that are caused by 27 fluctuation in price as opposed to reductions in the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction in the ultimate value of the related reserves. Oil and gas prices declined sharply in 2001, from near record levels at the end of 2000, significantly reducing the future net revenues attributable to Mission's reserves. Using the year end prices of $19.76 per barrel of oil and $2.73 per MMBTU of gas, adjusted to the wellhead by applying current price differentials, a pretax impairment charge of $20.8 million ($13.5 million net of tax) was calculated and recorded. No such write down was required for the years ended December 31, 2000 and 1999. Fair Value of Derivative Instruments The estimated fair values of Mission's commodity derivative instruments are recorded in Mission's consolidated balance sheet. All of Mission's commodity derivative instruments represent hedges of the price of future oil and natural gas production. While fair values of such hedging instruments must be estimated as of the end of each reporting period, the changes in the fair value for effective hedge instruments are not included in Mission's results of operations. Instead, the changes in fair value of effective hedging instruments are recorded directly to stockholders' equity until the hedged oil or natural gas quantities are produced. Estimating the fair values of hedging derivatives would require Mission to use substantial judgement using a discounted cash flow technique, including estimates of future NYMEX prices and the appropriate discount rate, making the resulting fair values inherently imprecise. As a result, Mission chooses to obtain the fair value of its commodity derivatives from the counterparties to those contracts. Since the counterparties are market makers, they are able to provide Mission with a literal market value, or what they would be willing to settle such contracts for as of the given date. Mission also obtains the fair value of its financial derivative contract, the interest rate swap, from the counterparty to the contract. The interest rate swap is marked to market each quarter, with any changes in fair value recorded in earnings, because it does not qualify for hedge accounting. Business Combinations and Goodwill Mission has grown substantially during the year through the acquisition of Bargo on May 16, 2001. This acquisition has been accounted for using the purchase method of accounting, and 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. As of January 1, 2002, the accounting for goodwill has changed. In prior years, goodwill was amortized over its estimated useful life. As of 2002, goodwill with an indefinite useful life is no longer amortized, but instead is assessed for impairment at least annually. There are various assumptions made by Mission in determining the fair values of an acquired company's assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, Mission prepares estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by Mission's outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation. However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies current price and cost information to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must be based on Mission's estimates of future oil, natural gas and NGL prices. In order to reduce the impact of management judgment and 28 the possibly resulting inaccuracies, Mission chooses to use future price forecasts from independent third parties, adjusted to the wellhead for its historically realized price differentials, in estimating the fair values of acquisitions. These estimated future prices are applied to the estimated reserve quantities acquired to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a 15% per annum rate. Mission also applies 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. 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, the discounted future net revenues of probable and possible reserves are reduced by what Mission considers to be an appropriate risk-weighting factor in 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. In aggregate, the discounted future net revenues of probable and possible reserves are reduced by factors ranging from 30% to 90% to arrive at what Mission considers to be the appropriate fair values. In Mission's business combination with Bargo, the determination of the fair values of oil and gas properties required more judgment than the fair values of other current assets and liabilities. The future price forecasts of Goldman Sachs, as published in January 2001, were applied to the estimated Bargo reserve quantities obtained from Netherland, Sewell & Associates, Inc. and T. J. Smith & Company, Inc. in order to obtain estimated future net revenues of Bargo. The fair value of proved properties acquired was determined by discounting the resulting estimated future net revenues at a 15% per annum rate. The fair value of unproved reserves was determined by reducing, due to risk, the discounted future net revenues of the probable and possible reserves by a factor of 86%. The risking factor was an aggregate of the factors determined for each field by Mission's engineering staff. 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. Mission may have an interest with other producers in certain properties. In this case, Mission uses 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. No provision is made on the balance sheet to account for potential amounts due to or from Mission related to gas imbalances. The settlement or disposition of gas balancing positions as of December 31, 2001 is not anticipated to adversely impact Mission's financial condition. 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 2002 2003 2004 2005 2006 Thereafter ---------------- -------- ------- ------- ------- ------- ------- ---------- Long Term Debt*......... $353,462 $24,469 $24,469 $24,469 $24,469 $24,469 $231,117 Operating Leases........ 3,820 819 597 601 601 601 601 -------- ------- ------- ------- ------- ------- -------- Total Contractual Obligations............ $357,282 $25,288 $25,066 $25,070 $25,070 $25,070 $231,718 ======== ======= ======= ======= ======= ======= ========
-------- * Bond principle of $225.0 million scheduled for repayment in 2007. Bond interest is payable April 1 and October 1 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 2002 2003 2004 2005 2006 Thereafter ----------------------- ------- ------ ------ ------- ------ ------ ---------- Line of Credit.......... $35,000 $ -- $ -- $35,000 $ -- $ -- $ -- Other Commercial Commitments............ 15,159 6,478 2,301 2,028 1,966 1,935 451 ------- ------ ------ ------- ------ ------ ---- Total Commercial Commitments.......... $50,159 $6,478 $2,301 $37,028 $1,966 $1,935 451 ======= ====== ====== ======= ====== ====== ====
30 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, --------------------------- 2001(2) 2000 1999 -------- -------- ------- Oil and gas revenues--US...................... $131,358 $107,938 $68,264 Oil revenues--Ecuador......................... 1,877 4,315 -- Gas plant revenues............................ 4,456 6,070 3,830 Interest and other............................ 4,386 957 1,335 -------- -------- ------- Total revenue............................. 142,077 119,280 73,429 Production expenses--US....................... 48,134 27,694 21,515 Production expenses--Ecuador.................. 3,071 2,815 17 Transportation Costs.......................... 73 270 316 Gas plant expenses............................ 2,118 2,677 2,366 Depreciation, depletion and amortization--US.. 44,602 31,909 23,863 Depreciation, depletion and amortization-- Ecuador...................................... 504 745 -- Impairment expense............................ 27,057 -- -- Disposition of hedges......................... -- 8,671 -- Uncollectible gas revenues.................... 2,189 -- -- Mining venture................................ 914 -- -- Loss on sale assets........................... 11,600 -- -- General and administrative expenses........... 15,384 9,138 7,848 Interest expense.............................. 23,664 15,375 11,845 Income tax benefit............................ (9,055) (12,222) (3,154) -------- -------- ------- Net income (loss) before cumulative effect of changes in accounting method................. (28,178) -- -- ======== ======== ======= Cumulative effect of a change in accounting method, net of deferred tax 2,767 -- -- ======== ======== ======= Net income (loss)............................. $(30,945) $ 32,208 $ 8,813 ======== ======== ======= Production Oil and condensate (MBBLS)--US.............. 3,303 2,206 2,080 Oil and condensate (MBBLS)--Ecuador......... 95 174 -- (1) Natural gas (MMCF).......................... 17,597 20,478 18,965 Oil equivalent (MBOE)....................... 6,331 5,793 5,241 Average sales price, including the effect of hedges Oil and condensate (per BBL)--US............ $ 22.30 $ 20.53 $ 12.84 Oil and condensate (per BBL)--Ecuador....... $ 19.76 $ 24.80 -- (1) Natural gas (per MCF)....................... $ 3.28 $ 3.06 $ 2.19 Average sales price, excluding the effect of hedges Oil and condensate (per BBL)--US............ $ 21.81 $ 24.40 $ 14.48 Oil and condensate (per BBL)--Ecuador....... $ 19.76 $ 24.80 -- (1) Natural gas (per MCF)....................... $ 4.13 $ 3.84 $ 2.22 Average production expenses per BOE--US....... $ 7.72 $ 4.93 $ 4.11 Average production expenses per BOE--Ecuador.. $ 32.33 $ 16.18 -- (1) Average G&A expenses per BOE.................. $ 2.43 $ 1.58 $ 1.50 Average depletion rate per BOE--US............ $ 6.72 $ 5.46 $ 4.32 Average depletion rate per BOE--Ecuador....... $ 5.31 $ 4.28 -- (1)
-------- (1) There was no Ecuador production in 1999. (2) Operations of properties acquired from Bargo began May 16, 2001 and Ecuador operations ceased June 2001. 31 Operations of the gas plants are summarized as follows:
Year Ended December 31, --------------------- 2001(1) 2000 1999 ------- ------ ------ Plant product sales volume (MBBLS)....................... 203 257 241 Average product sales price per barrel................... $18.15 $20.31 $12.93
-------- (1) The Snyder gas plant was sold in October 2001 and the Diamond M gas plant was sold in November 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. Decreases in oil and gas prices during the year, property impairments and a loss on sale of assets contributed significantly to the decline in earnings. 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. 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 decreased 9% from $62.7 million in 2000 to $57.7 million in 2001. Average realized gas prices, including hedge impact, had a slightly favorable impact, increasing 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 reflects the effects of the Company's sale of non-core short-life gas properties in 2000 combined with its shift toward more profitable and predictable, longer-lived oil production. The Company's Ecuador properties, sold in 2001, did not produce gas. 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 a 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 are reported in 2001 because the plants were sold within the year. Interest and Other Income--Interest and other income increased from $957,000 reported for the year 2000 to $3.9 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, $325,000 related to the Carpatsky transaction and the write off of $0.6 million of various receivables in 2001 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. Production Expenses--Total production expenses for the year 2001 totaled $51.2 million compared to $30.5 million in the year 2000. On a barrel equivalency basis, production expenses were $9.57 in 2001 and $5.27 in 32 2000. Domestic production expenses increased from $27.7 million in 2000 to $48.1 million in 2001. Production taxes are included in production expense and are calculated as a percentage of revenue in many areas; therefore, they vary much like realized prices. Production taxes on a per BOE basis remained essentially the same in both years. The most significant contribution to increased production expenses is the acquisition of properties. As a result of the acquisitions, 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 and have only recently begun to decline. Mission has been reviewing its properties for cost saving opportunities. Some of these opportunities require 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, account for $2.8 million of total production expenses in the year 2000 and $3.1 million in the year 2001. Gas Plant Expenses--Gas plant expenses decreased 22% from $2.7 million in 2000 to $2.1 million in the year 2001. The decrease is 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 are reported in 2001 because the plants were sold within the year. Transportation Costs--Transportation costs were not significant in either 2001 or 2000, however the decrease in such costs from $270,000 in 2000 to $73,000 in 2001 is due to the sale of one field in December 2000. Natural gas transportation costs for that field were a substantial portion of Mission's total transportation costs. Depreciation, Depletion and Amortization--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 properties were sold in June 2001. Impairment Expense--The non-cash impairment expense reported in 2001 consists of a $20.8 million full cost ceiling impairment and the non-recurring write off of the Company's $6.2 million long-term receivable. 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 which were deemed uncollectible in the fourth quarter of 2001. Uncollectible Gas Revenues--Mission chose to write off as uncollectible $2.2 million receivable from a subsidiary of Enron due to Enron's bankruptcy. Mining Venture--Since 1992, Mission has owned an interest in an exploratory stage mining venture. In 2001, the $729,000 of related costs that were reported in other assets on the December 31, 2000 Balance Sheet was a non-cash charge to earnings, plus an additional $185,000 spent in 2001 for soil core assays and evaluations was charged to earnings. Loss on Sale of Assets--The loss on sale of assets consists of a $12.7 million loss on the Company's sale of its Ecuadorian interests 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 $15.4 million in the year ended December 31, 2001 as compared to $9.1 million in the year ended December 31, 2000, for an increase of 69%. Salaries and benefits increased $2.8 million in 2001 over 2000 levels due to Mission's increased employee count due to 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. 33 Income Taxes--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 in Carpatsky, as 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. Therefore, the valuation allowance has been 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 due to the merger and the additional $125.0 million of bonds issued in May 29, 2001 contributed to the expense increase. Additionally, a set non-cash gain from the change is 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. Year Ended 2000 Compared to Year Ended 1999 Net Income--Net income for the year ended December 31, 2000 was $32.2 million, or $2.27 per share on a diluted basis, compared net income for the year ended December 31, 1999 of $8.8 million, or $0.63 per share on a diluted basis. Significant increases in oil and gas prices were primarily responsible for the improvement, but increased production also played a role. Oil and Gas Revenues--Oil and gas revenues were $112.3 million in the year ended December 31, 2000, as compared to $68.3 million for the respective period in 1999. Oil revenues increased to $49.6 million for the year 2000 from $26.7 million for the year 1999. Domestic oil revenues benefited from the 60% increase in realized oil prices from $12.84 in 1999 to $20.53 in 2000. Improved domestic oil production was primarily due to new wells in Southwest Louisiana and in the Gulf of Mexico. Sales of 174,000 barrels of Ecuadorian production, primarily from the Tiguino field, at an average price of $24.80 per barrel, accounted for the remainder of the oil revenue increase. Total oil production was 2,380,000 barrels during the year ended December 31, 2000 compared to 2,080,000 barrels for the year ended December 31, 1999. Gas revenues increased 51% from $41.6 million in 1999 to $62.7 million reported in 2000. Again, prices accounted for a large portion of the increase. Realized gas prices averaged $3.06 per MCF, or 40% higher, in the year ended December 31, 2000 as compared to $2.19 in the year ended December 31, 1999. Gas production was up 8% compared to the previous year with 20,478 MMCF and 18,965 MMCF in the years 2000 and 1999, respectively. The production increases were primarily due to continued exploration and development in Texas, Louisiana, and the Gulf of Mexico fields. Mission's Ecuador properties did not produce gas. The realized prices discussed above include the impact of oil and gas hedges. A decrease of $24.5 million related to hedge activity was reflected in oil and gas revenues for the year 2000, while a decrease in oil and gas revenues of $4.0 million was reflected for the previous year. For the year 2000, approximately 80% of domestic oil production and 73% of domestic gas production was hedged. Ecuadorian oil production was not hedged. 34 Mission entered into a gas swap for $4.60 per MCF on 15,000 MCF per day of production from November 2000 through October 2001. This offset the hedges previously existing on forecast production that was sold in late 2001. The non-cash loss of $8.7 million was recognized in the fourth quarter of 2000 related to the $4.60 swap. Gas Plant Revenues--Gas plant revenues were $6.1 million in 2000, compared to $3.8 million in 1999. A 57% increase in average realized plant liquid prices contributed to the higher revenue. Production Expenses--Production expenses for the year 2000 totaled $30.5 million, as compared to $21.5 million in the year 1999. On a barrel equivalency basis, production expenses were $5.27 per BOE in 2000 and $4.11 in 1999. Ecuadorian operations, which started in late 1999, account for $2.9 million, or $0.49 per BOE, of this increase. Most of the Ecuadorian field expenses were non-recurring, including repair and maintenance of production facilities and replacement of downhole pumps. Production taxes are included in this production expense category and are calculated as a percentage of revenue in many areas; therefore, they have increased with the increase in realized prices, contributing $ 0.28 per BOE. Price inflation has impacted many items like fuel, contract labor, and specialized services. Finally, the year 2000 included a number of workovers and maintenance projects in order to boost production levels. Gas Plant Expenses--Gas plant expenses increased from $2.4 million in 1999 to $2.7 million in the year 2000, or 13%. Such increase is small when compared to the 61% increase in revenues. While Snyder Gas Plant costs for purchased natural gas increased along with commodity prices, the Diamond M plant's gas purchase costs decreased in proportion to revenues. One of the gas plant partners, which also provides significant quantities of gas to the plant, elected to take its reimbursement in-kind, receiving a share of the products. Transportation Costs--Transportation costs were not significant in either 2000 or 1999. Depreciation, Depletion, and Amortization - DD&A increased 37% to $32.7 million in 2000 versus $23.9 million in 1999. Depletion of the Ecuadorian full cost pool for this year was $745,000. Improvements in domestic production in the year 2000 increased the absolute amount of DD&A, but accelerated capital expenditures caused a $0.99 increase in the per BOE rate. Total company DD&A per BOE was $5.37 and $4.32 for the years ended December 31, 2000 and 1999, respectively. General and Administrative Expenses--General and administrative expenses totaled $9.1 million in the year ended December 31, 2000 compared to $7.8 million in the year ended December 31, 1999. Significantly lower than normal outsourcing costs in 1999 contributed to the difference. Management fees were $2.9 million in 1999 and $4.7 million in 2000. Prior to October 1999, Mission was charged a management fee based upon a specified percentage of the average book value of the Company's total assets, excluding cash, plus a percentage of operating cash flows. Due to the $73.9 million impairment charge in December 1998, the Company's total assets and resulting percentage of such assets was reduced. In October 1999, the Company became party to a new MSA and six specific contracts, which covered comparable outsourcing services to those contained in the 1999 contract. Other significant items in general and administrative expenses included a $1.7 million charge in 1999 due to a change in management and a $849,000 non- cash charge in 2000 required due to the difference between exercise and grant date prices on options awarded to the Company president. Interest Expense--Interest expense increased 30% to $15.4 million for the year ended December 31, 2000 from $11.8 million in the year ended December 31, 1999. Increased interest rates and higher borrowings outstanding during the period resulted in the increase. Although outstanding debt of $125.5 million at December 31, 2000 was lower than the $130.0 million outstanding at December 31, 1999, most of the $30.0 million credit facility borrowings in 1999 were incurred in the latter half of the year, whereas borrowings during 2000 reached maximums of $40.9 million. Additional expenses of $705,000 incurred in conjunction with the credit facility amendments were also charged to interest expense in 2000. 35 Income Taxes--At December 31, 1999, the Company had a tax valuation allowance of $19.8 million against its deferred tax assets. A portion of the valuation allowance was recognized in 1999.In 2000, the Company determined that it was more likely than not that the deferred assets would be realized, based upon current projections of taxable income due to higher commodity prices, and the valuation allowance was removed. 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 New Credit Facility limit the amount of dividends that may be declared. Mission maintains a policy, which is subject to review from time to time by the Board of Directors, of reinvesting its discretionary cash flows for the continued growth of the company. Derivative Financial Instruments Mission periodically uses derivative financial instruments to manage oil and gas price risk and interest rate risk. For purposes of its hedging activities, Mission divides product price risks into two categories, fluctuations in the price of oil and gas on the NYMEX and fluctuations in the difference between NYMEX prices and the price actually received by Mission for its production (referred to as "basis differential"). From time to time Mission enters into swap transactions in which it agrees to pay a fixed price and the counter party to the swap agrees to pay a NYMEX based price. Effective September 22, 1998, the Company entered into an eight and a half- year interest rate swap agreement with a notional value of $80.0 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are re-determined for a six-month period each April 1 and October 1. Through April 2002 the floating rate is capped at 10.875% and capped at 12.375% thereafter. The floating rate for the period from October 1, 2001 to April 1, 2002 is 9.87%. Beginning in 2001, the interest rate swap did not qualify for hedge accounting. It is marked to market quarterly. New Accounting Pronouncements In July 2001, the FASB issued Statement No. 141, Business Combinations, and Statement No.142, Goodwill and Other Intangible Assets. Statement No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 as well as all purchase method business combinations completed after June 30, 2001. Statement No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet in order to be recognized and reported apart from goodwill, noting that any purchase price allocable to an assembled workforce may not be accounted for separately. Statement No. 142 will require that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of Statement No. 142. Statement No. 142 will also require that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. Mission is required to adopt the provisions of Statement No. 141 immediately and Statement No. 142 effective January 1, 2002. As of the date of adoption, Mission expects to have unamortized goodwill in the amount of $15.1 million and unamortized identifiable intangible assets in the amount of $374,300, all of which will be subject to the transition provisions of Statements No. 141 and No. 142. Amortization expense related to goodwill was $986,000 for the period ended December 31, 2001. Upon adoption of SFAS No. 142, amortization of goodwill and intangible assets will cease, thereby reducing expenses by approximately $456,000 quarterly. Since such amortization is not an allowable deduction for calculating taxes, Mission's effective tax rate will decrease. Also, 36 upon adoption of SFAS No. 142, $277,000 of workforce intangible currently recorded as unamortized identifiable intangible assets will be subsumed into goodwill and will not be amortized as it no longer qualifies as a recognizable intangible asset. Because of the extensive effort needed to comply with adopting Statements No. 141 and No. 142, it is not practicable to reasonably estimate all of the potential impacts of adopting these statements on Mission's financial statements at the date of this report. In July 2001, FASB issued Statement No. 143. SFAS No. 143, Accounting for Asset Retirement Obligations, provides 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. SFAS No. 143 requires that asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Mission will adopt the statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS No. 143 will be reported as a cumulative effect of a change in accounting principle. At this time, Mission cannot reasonably estimate the effect of the adoption of this statement on either financial position or results of operations. In August 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which will be effective as of January 1, 2002. SFAS No. 144 requires that long-lived assets to be disposed of by sale be measured at the lower of the carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. After its effective date, SFAS No. 144 will be applied to those transactions where appropriate. At this time Mission is unable to determine what the future impact of adopting this statement will have on its financial position or results of operations. Item 7a. Quantitative and Qualitative Disclosures About Market Risk Mission is exposed to market risk, including adverse changes in commodity prices and interest rate. Commodity Price Risk--Mission 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. Mission 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, are Mission's preferred hedge instruments because there are no up-front costs and protection is given against low prices. These hedges assure that the revenues Mission receives on the hedged production will be at prices no lower than the price floor and no higher than the price ceiling. 37 The following details Mission's hedges of future production that were in place at March 15, 2002. Oil Hedges
BBLS NYMEX NYMEX Per Total Price Price Period Day BBLS Type Floor Ceiling ------ ------ --------- ------ ------ ------- Jan. 2002-Mar. 2002................... 6,000 540,000 Collar $21.50 $31.25 Apr. 2002-June 2002................... 5,400 491,400 Collar $21.50 $30.25 Apr. 2002-June 2002................... 500 45,500 Collar $21.00 $26.25 Apr. 2002-June 2002................... 500 45,500 Collar $21.00 $25.05 July 2002-Sep. 2002................... 4,700 432,400 Collar $21.50 $28.45 July 2002-Sep. 2002................... 500 46,000 Collar $21.00 $25.03 July 2002-Sep. 2002................... 500 46,000 Collar $21.00 $26.00 Oct. 2002-Dec. 2002................... 4,000 368,000 Collar $21.50 $27.15 Oct. 2002-Dec. 2002................... 500 46,000 Collar $21.00 $25.01 Oct. 2002-Dec. 2002................... 500 46,000 Collar $21.00 $25.25 Jan. 2003-Mar. 2003................... 2,500 225,000 Collar $20.50 $24.11 Jan. 2003-Mar. 2003................... 500 45,000 Collar $21.00 $25.00 Apr. 2003-June 2003................... 2,500 227,500 Collar $20.50 $24.08 Apr. 2003-June 2003................... 500 45,500 Collar $21.00 $24.65 July 2003-Sep. 2003................... 2,500 230,000 Collar $20.50 $24.05 July 2003-Sep. 2003................... 500 46,000 Collar $20.50 $24.50 Oct. 2003-Dec. 2003................... 2,500 230,000 Collar $20.50 $24.02 Oct. 2003-Dec. 2003................... 500 46,000 Collar $20.50 $24.25 Gas Hedges MCF NYMEX NYMEX Per Price Price Period day Total MCF Type Floor Ceiling ------ ------ --------- ------ ------ ------- Jan. 2002-Mar. 2002................... 11,700 1,053,000 Collar $ 3.57 $ 7.00 Apr. 2002-June 2002................... 10,200 928,200 Collar $ 3.00 $ 6.48 July 2002-Sep. 2002................... 9,800 901,600 Collar $ 3.00 $ 6.60 July 2002-Sep. 2002................... 10,000 920,000 Collar $ 2.50 $ 3.55 Oct. 2002-Dec. 2002................... 8,500 782,000 Collar $ 3.40 $ 7.00 Jan. 2003-Mar. 2003................... 10,000 900,000 Collar $ 3.00 $ 4.65 Apr. 2003-June 2003................... 5,000 455,000 Collar $ 3.00 $ 4.02 Apr. 2003-June 2003................... 5,000 455,000 Collar $ 3.00 $ 3.97 July 2003-Sep. 2003................... 10,000 920,000 Collar $ 3.00 $ 4.10 Oct. 2003-Nov. 2003................... 10,000 920,000 Collar $ 3.00 $ 4.65
These commodity swap agreements expose Mission to counterparty credit risk to the extent the counterparty is unable to met its monthly settlement commitment to Mission. Mission believes it selects creditworthy counterparties to its hedge transactions. Each of Mission's counterparties have long term senior unsecured debt ratings of at least A/A2 by Standard & Poor or Moody's. Interest Rate Risk--Mission may enter into financial instruments such as interest rate swaps to manage the impact of interest rates. Effective September 22, 1998, Mission entered into an eight and one-half year interest rate swap agreement with a notional value of $80.0 million. Under the agreement, Mission receives a fixed interest rate and pays a floating interest rate, subject to a cap, based on the simple average of three foreign LIBOR rates. Floating rates are re-determined for a six-month period each April 1 and October 1. Through April 1, 2002, the floating rate is capped at 10.875% and capped at 12.375% thereafter. The floating rate for the period from October 1, 2001 to April 1, 2002 is 9.87%. Mission's exposure to changes in interest rates primarily results from short-term changes in the LIBOR rates. A 10% change in the floating LIBOR rates would change interest costs to Mission by $791,000 per year. This agreement is not held for trading purposes. The swap provider is a major financial institution, and Mission does not anticipate non-performance by the provider. 38 Item 8. Financial Statements and Supplementary Data INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page Number ------ Independent Auditors' Report............................................ 41 Financial Statements: Consolidated Balance Sheets as of December 31, 2001 and 2000.......... 42 Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000 and 1999.................................................. 44 Consolidated Statements of Changes in Stockholders' Equity and Comprehensive Loss the Years Ended December 31, 2001, 2000 and 1999.. 45 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999.................................................. 46 Notes to Consolidated Financial Statements............................ 47
39 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, 2001 and 2000 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, 2001. 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, 2001 and 2000 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. 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 February 28, 2002 40 MISSION RESOURCES CORPORATOIN AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, December 31, 2001 2000 ASSETS ------------ ------------ (Amounts in thousands) CURRENT ASSETS: Cash and cash equivalents............................ $ 603 $ 14,464 Accounts receivable and accrued revenues............. 25,668 27,724 Current portion of interest rate swap................ 180 -- Commodity derivative asset........................... 8,359 -- Notes receivable-affiliate........................... -- 1,281 Prepaid expenses and other........................... 3,879 1,189 --------- --------- Total current assets............................... 38,689 44,658 --------- --------- PROPERTY, PLANT AND EQUIPMENT, at cost: Oil and gas properties (full cost) United States--Unproved properties of $15,530 and $11,360 excluded from amortization as of December 31, 2001 and 2000, respectively................... 753,905 421,408 Ecuador--No unproved properties as of December 31, 2001 and 2000, respectively....................... -- 12,988 Gas plant facilities................................. -- 18,452 --------- --------- 753,905 452,848 Accumulated depreciation, depletion and amortization--oil and gas........................... (374,167) (296,567) Accumulated depreciation, depletion and amortization--gas plant............................. -- (7,345) Net property, plant and equipment.................... 379,738 148,936 --------- --------- Leasehold, furniture and equipment................... 3,347 2,782 Accumulated depreciation............................. (916) (404) --------- --------- Net leasehold, furniture and equipment............... 2,431 2,378 --------- --------- LONG TERM RECEIVABLE................................. 899 4,554 GOODWILL & OTHER INTANGIBLES......................... 15,436 -- DEFERRED INCOME TAXES................................ -- 15,141 OTHER ASSETS......................................... 10,571 5,878 --------- --------- $ 447,764 $ 221,545 ========= =========
See Notes to Consolidated Financial Statements. 41 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, December 31, 2001 2000 LIABILITIES AND STOCKHOLDERS' EQUITY ------------ ------------ (Amounts in thousands, except share information) CURRENT LIABILITIES: Accounts payable and accrued liabilities............. $ 38,584 $ 29,960 Commodity derivative liabilities..................... -- 7,486 -------- -------- Total current liabilities.......................... 38,584 37,446 -------- -------- LONG-TERM DEBT, including $1.7 million unamortized premium on issuance of $125 million bonds........... 261,695 125,450 INTEREST RATE SWAP, excluding current portion........ 4,248 -- DEFERRED INCOME TAXES................................ 31,177 -- OTHER LIABILITIES.................................... 1,820 1,689 STOCKHOLDERS' EQUITY: Preferred stock, $0.01 par value, 5,000,000 shares authorized; none issued or outstanding at December 31, 2001 and 2000................................... -- -- Common stock, $0.01 par value, 60,000,000 shares authorized, 23,896,959 and 14,259,626 shares issued at December 31, 2001 and December 31, 2000, respectively...................................... 239 143 Additional paid-in capital........................... 163,735 81,892 Retained deficit..................................... (54,115) (23,170) Treasury stock, at cost, 311,000 shares.............. (1,905) (1,905) Other comprehensive income, net of taxes............. 2,286 -- -------- -------- Total stockholders' equity......................... 110,240 56,960 -------- -------- $447,764 $221,545 ======== ========
See Notes to Consolidated Financial Statements. 42 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2001 2000 1999 ------------ ------------ ------------ (Amounts in thousands, except per share data) REVENUES: Gas revenues......................... $ 57,705 $ 62,652 $41,559 Oil revenues--United States.......... 73,653 45,286 26,705 Oil revenues--Ecuador................ 1,877 4,315 -- Gas plant revenues................... 4,456 6,070 3,830 Interest and other income............ 4,386 957 1,335 -------- -------- ------- 142,077 119,280 73,429 -------- -------- ------- COSTS AND EXPENSES: Production expenses--United States... 48,134 27,694 21,515 Production expenses--Ecuador......... 3,071 2,815 17 Transportation costs................. 73 270 316 Gas plant expenses................... 2,118 2,677 2,366 Depreciation, depletion and amortization--United States......... 44,602 31,909 23,863 Depreciation, depletion and amortization--Ecuador............... 504 745 -- Impairment expense................... 27,057 -- -- Disposition of hedges................ -- 8,671 -- Uncollectible gas revenues........... 2,189 -- -- Mining venture....................... 914 -- -- Loss on sale of assets............... 11,600 -- -- General and administrative expenses.. 15,384 9,138 7,848 Interest expense..................... 23,664 15,375 11,845 -------- -------- ------- 179,310 99,294 67,770 -------- -------- ------- Income (loss) before income tax benefit and cumulative effect of a change in accounting method..................... (37,233) 19,986 5,659 Provision for income tax benefit....... (9,055) (12,222) (3,154) -------- -------- ------- Income (loss) before cumulative effect of a change in accounting method...... $(28,178) $ 32,208 $ 8,813 Cumulative effect of a change in accounting method, net of tax of $1,633................................ 2,767 -- -- -------- -------- ------- Net income (loss)...................... $(30,945) $ 32,208 $ 8,813 ======== ======== ======= Income (loss) before cumulative effect of a change in accounting method...... $ (1.41) $ 2.32 $ 0.64 ======== ======== ======= Income (loss) before cumulative effect of a change in accounting method-- diluted............................... $ (1.41) $ 2.27 $ 0.63 ======== ======== ======= Net income (loss) per share............ $ (1.54) $ 2.32 $ 0.64 ======== ======== ======= Net income (loss) per share--diluted... $ (1.54) $ 2.27 $ 0.63 ======== ======== ======= Weighted average common shares outstanding........................... 20,051 13,899 13,854 ======== ======== ======= Weighted average common shares outstanding--diluted.................. 20,241 14,175 13,896 ======== ======== =======
See Notes to Consolidated Financial Statements. 43 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE LOSS
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, 1998................... 14,165 $142 -- $-- $ 80,442 -- $(64,191) (311) $(1,904) $ 14,489 ====== ==== === === ======== ====== ======== ==== ======= ======== Stock options exercised and related tax effect................. 4 -- -- -- 13 -- -- -- -- 13 Treasury shares purchased.............. -- -- -- -- -- -- -- -- (1) (1) Net income.............. -- -- -- -- -- -- 8,813 -- -- 8,813 ------ ---- --- --- -------- ------ -------- ---- ------- -------- Balance December 31, 1999................... 14,169 $142 -- $-- $ 80,455 -- $(55,378) (311) $(1,095) $ 23,314 ====== ==== === === ======== ====== ======== ==== ======= ======== Stock options exercised and related tax effects................ 91 1 -- -- 588 -- -- -- -- 589 Compensation expense-- stock options.......... -- -- -- -- 849 -- -- -- -- 849 Treasury shares purchased.............. -- -- -- -- -- -- -- -- -- -- 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 -- -- 1,139 -- -- -- -- 1,141 Issuance of common stock related to merger...... 9,460 94 -- -- 79,905 -- -- -- -- 79,999 Compensation expense-- stock options.......... -- -- -- -- 799 -- -- -- -- 799 Treasury shares purchased.............. -- -- -- -- -- -- -- -- -- -- 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 ====== ==== === === ======== ====== ======== ==== ======= ========
See Notes to Consolidated Financial Statements. 44 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2001 2000 1999 ------------ ------------ ------------ (Amounts in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)...................... $ (30,945) $ 32,208 $ 8,813 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization........................ 45,106 32,654 23,863 Gain on Interest rate swap........... (332) -- -- Gain due to hedge ineffectiveness.... (4,767) -- -- Mining venture....................... 729 -- -- Cumulative effect of a change in accounting method, net of deferred tax................................. 2,767 -- -- Amortization of stock options........ 799 849 -- Amortization of deferred financing costs and bond premium.............. 1,877 559 831 Loss on sale of assets............... 11,600 -- -- Disposition of hedges................ -- 8,671 -- Impairment expense................... 27,057 -- -- Other................................ 455 -- -- Deferred taxes....................... (9,650) (12,307) (2,739) --------- -------- -------- 44,696 62,634 30,768 Changes in assets and liabilities, net of acquisition effects: Accounts receivable and accrued revenues............................ 5,669 (13,370) 2,101 Prepaid expenses and other........... (3,025) 373 157 Accounts payable and accrued liabilities......................... (5,611) 12,217 6,265 Due to affiliates.................... -- -- (125) Abandonment costs.................... (1,371) (1,531) (136) Other................................ -- (215) (411) --------- -------- -------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES............................ 40,358 60,108 38,619 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions of oil and gas properties.......................... (24,159) (7,078) (25,889) Acquisitions of Bargo oil and gas properties.......................... (142,028) -- -- Proceeds on sale of oil and gas properties, net..................... 15,868 45,906 5,139 Proceeds on sale of assets, net...... 15,668 -- -- Additions to oil and gas properties.. (48,040) (81,294) (30,904) Additions to gas plant facilities.... (1,047) (677) (369) Additions to leasehold, furniture and equipment........................... (527) (2,462) (448) Investment in outside companies...... -- -- (4,426) Note receivable...................... -- (1,281) -- Other................................ -- (446) (1,071) --------- -------- -------- NET CASH FLOWS USED IN INVESTING ACTIVITIES............................ $(184,265) $(47,332) $(57,968) ========= ======== ========
See Notes to Consolidated Financial Statements. 45 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2001 2000 1999 ------------ ------------ ------------ (Amounts in thousands) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings............... $ 208,754 $ 31,400 $ 42,000 Net proceeds from stock option exercises............................. 899 496 12 Payments of long-term debt............. (199,204) (35,950) (16,400) Proceeds from issuance of senior subordinated notes due 2007, including premium 126,875 Credit facility costs.................. (7,278) (359) (172) --------- -------- -------- NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES.................. 130,046 (4,413) 25,440 --------- -------- -------- Net increase (decrease) in cash and cash equivalents...................... (13,861) 8,363 6,091 Cash and cash equivalents at beginning of period................... 14,464 6,101 10 --------- -------- -------- Cash and cash equivalents at end of period............................. $ 603 $ 14,464 $ 6,101 ========= ======== ========
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 ========
See Notes to Consolidated Financial Statements. 46 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 acquire, 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 acquisitions, property enhancement through exploitation and development drilling, low- to moderate-risk exploration, asset redeployment and operating cost reduction. On May 16, 2001, Bellwether Exploration Company ("Bellwether") merged with Bargo Energy Company ("Bargo") and changed its name to Mission Resources Corporation. Simultaneously with the merger, Bellwether increased its authorized capital stock to 65.0 million shares and amended its 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. 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. Snyder Gas Plant Venture and NGL/Torch Gas Plant Venture and their 11.9% and 32.0% investments in the Snyder and Diamond M-Sharon Ridge Gas Plants have been pro rata consolidated through September 1999 at which time the joint ventures were dissolved. Although the joint ventures were dissolved, the Company retained its interests in the gas plants on the parent company's books until the interests in both gas plants were sold in 2001. In 1999 the Company reflected its investment in Carpatsky using the equity method. The Company's December 30, 1999 investment in Carpatsky did not result in the reflection of any equity in earnings during 1999. 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 income 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 which are capitalized are primarily the salary and benefits of geologists and engineers directly involved in acquisition, exploration and development activities, and amounted to $3.2 million, $3.3 million and $1.7 million in the years ended December 31, 2001, 2000 and 1999, respectively. Until June 2001, the Company had two full cost pools: United States and Ecuador. As of December 31, 2001 only the United States full cost pool remained. 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. 47 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 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 $6.72 in 2001, $5.47 in 2000, and $4.32 in 1999. Depletion expense per equivalent barrel of Ecuador production was $4.28 in 2000. 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 2001 --------- ----------- ----------- ------------ Costs Incurred During Periods Ended: December 31, 2001........ $ 5,869 $2,877 $48 $ 8,794 December 31, 2000........ 350 -- -- 350 December 31, 1999........ 4,958 -- -- 4,958 Prior.................... 1,428 -- -- 1,428 ------- ------ --- ------- $12,605 $2,877 $48 $15,530 ======= ====== === =======
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 which have not resulted in the recognition of reserves at December 2001. This category of costs will transfer into the full cost pool in 2002. Included in leasehold costs are land and seismic costs incurred in the current and prior years by the Company and are still in the evaluation stage. Approximately $1.8 million, $2.8 million and $1.2 million were evaluated and moved to the full cost pool in 2001, 2000 and 1999, 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 $15.9 million, $ 46.0 million, and $ 5.1 million were recorded in such manner during the years 2001, 2000, and 1999, 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. Oil and gas prices declined throughout 2001, ending trading for the year at $19.76 per barrel of oil (NYMEX WTI Cushing) and $2.73 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 48 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) commodity hedges that qualify for hedge accounting under SFAS No. 133. This adjustment was calculated by taking the difference between the closing NYMEX prices originally used and the price floors on the Company's hedges multiplied by the hedged volumes that were included in proved reserves. This calculation resulted in an increase in discounted future net revenues of $5.7 million because prices prevailing at December 31, 2001 were consistently lower than the Company's price floors. The Company's capitalized costs were in excess of these adjusted discounted future net revenues. The Company recorded an oil and gas property impairment of $20.8 million in 2001. Had the impact of hedges been omitted from this calculation, the impairment would have been $24.3 million in 2001. No such impairment to capitalized costs was required for 2000 or 1999. Any reference to oil and gas reserve information in the Notes to Consolidated Financial Statements is unaudited. Gas Plants and Gas Gathering System Gas plant facilities include the costs to acquire certain gas plants and to secure rights-of-way. Capitalized costs associated with gas plants facilities are amortized primarily over the estimated useful lives of the various components of the facilities utilizing the straight-line method. The estimated useful lives of such assets range from four to fifteen years. Effective September 1, 1999, NGL Associates , the Company's partner in the Torch-NGL Joint Venture and the Snyder Gas Plant Joint Venture (the "Ventures"), was given 16.5% of the Ventures' interests in order to satisfy requirements of the joint ventures. The result of this transfer of interests was the dissolution of the joint ventures. Mission's interest in the gas plants was reduced to 11.9% and 32.0% in the Snyder and Diamond M gas plants, respectively. 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. Prior year financial statements have been restated to present gas plant revenues on a gross basis in compliance with EITF 99-19. The presentation did not impact previously reported net income (loss) or net income (loss) per share for the periods presented. The Company sold its gas gathering subsidiary for $40,000 on March 1, 1999. 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 on its behalf. Revenues are recognized and accrued as production occurs. Sales to subsidiaries of Torch Energy Advisors ("Torch") accounted for greater than 10% of oil and gas revenues in 2001, 2000, and 1999. The sales amounts were $43.3 million, $26.9 million, and $14.9 million, respectively, and were part of domestic revenues. No other purchaser accounted for more than 10% of 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. The Company had a net imbalance liability, at fair 49 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) value, determined by applying average realized prices for the year to the imbalance volumes of $0.7 million, $2.3 million, and $1.2 million at December 31, 2001, 2000 and 1999, respectively. A certain portion of the gas balancing liability is related to properties approaching depletion; therefore, cash settlement may be likely. The Company is taking steps divest itself of such properties or to extend the productive life of such reserves. 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. The Company has recognized bad debt expense, included in interest and other income on the Statement of Operations, of $430,000, $135,000 and $23,000 related to such receivables for the years ended December 31, 2001, 2001 and 1999, respectively. 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 has not been 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 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 debt 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, 2001, 2000 and 1999, was $19.0 million, $13.8 million, and $11.1 million, respectively. Income tax refunds received in cash for December 31, 1999 were $437,000. 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. Benefit Plans During 1993, the Company adopted the Mission Resources Simplified Employee Pension Plan (the "Savings Plan") whereby all employees of the Company are eligible to participate. The Savings Plan is administered by a Plan Administrator appointed by the Company. Eligible employees may contribute a portion of their annual compensation up to the legal maximum established by the Internal Revenue Service for each plan year. The Company matches contributions up to a maximum of 6% each plan year. Employee contributions are immediately vested and employer contributions have a five-year vesting period. Amounts contributed by the Company to the Savings Plan for the years ended December 31, 2001, 2000 and 1999 were $405,000, $312,000, and $191,000, respectively. 50 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Deferred Compensation Plan In late 1997, the Company adopted the Mission Deferred Compensation Plan. This plan, which is not required to be funded, 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, 2001, 2000 and 1999 and was approximately $124,000, $25,000, and $98,000, respectively. 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, 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 core assays and evaluations. These exploratory costs, plus the $729,000 accumulated on the Balance Sheet in Other Assets as of December 31, 2000, were charged to earnings in 2001. Goodwill In evaluating the recovery of goodwill, Mission Resources compared the undiscounted future cash flows of its operations to the historical value of its net assets. An impairment of goodwill is measured as the excess in the historical value of the company's net assets over the undiscounted future cash flows of its operations. 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, 2001 and 2000 was as follows (in thousands):
Twelve Months Ended December 31, ----------------- 2001 2000 -------- ------- Net income (loss)......................................... $(30,945) $32,208 Cumulative effect attributable to adoption of SFAS No. 133, net of tax................................. (19,328) -- Hedge accounting for derivative instruments, net of tax... 21,614 -- -------- ------- Comprehensive income (loss)............................... $(28,659) $32,208 ======== =======
The accumulated balance of other comprehensive income related to cash flow hedges, net of taxes, is as follows (in thousands): Balance at December 31, 2000....................................... $ -- 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 ========
51 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Change in Accounting Method Effective January 1, 2001, the Company adopted the Statement of Financial Accounting Standards ("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 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 change 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 133, is recognized immediately in earnings. Adoption of SFAS No.133 at January 1, 2001 resulted in the recognition of $25.3 million of derivative liabilities included in Current Liabilities on the Balance Sheet and $19.3 million, net of taxes, of hedging losses included in Accumulated Other Comprehensive Income, a component of Stockholders' Equity, as the cumulative effect of a change in accounting method. Amounts were determined as of January 1, 2001 based upon quoted commodity prices. The Company also recognized a $4.4 million liability and a $2.8 million loss, net of taxes, as the cumulative effect of a change in accounting method related to an interest rate swap that did not qualify for hedge accounting treatment. 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, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are re-determined for a six-month period each April 1 and October 1. The interest rate swap did not qualify for hedge accounting under SFAS No. 133 at January 1, 2001. The swap's net value of $4.0 million is reflected on the balance sheet as a $180,000 current asset and a $4.2 million long-term liability. The change in the swap's fair value of $332,000 for the year ended December 31, 2001 has been reflected as a reduction in interest expense on the Statement of Operations. Mission entered into a gas swap for $4.60 per MCF on 15,000 MCF per day of production from November 2000 through October 2001. This offset hedges previously existing on forecasted production that was sold in late 2000. A non-cash loss of $8.7 million was recognized in the fourth quarter of 2000 related to the $4.60 swap, along with a current derivative liability as this portion of the swap was considered a speculative derivative. The liability was relieved monthly as the swap was settled. By December 31, 2001, the liability had been reduced to zero. Bargo had entered into one derivative contract, a floor of $21 per barrel on oil that extended into the year 2001. In adopting SFAS No. 133, it was determined that the Bargo derivative contract would be marked to market. Mission acquired this contract at the time of the merger. The contract was marked to market through December 31, 2001 at such time as the contract expired and related market value was zero. The actual results of this contract were offset against the changing market value, resulting in a net derivative loss of $75,000 recorded to other income on the Statement of Operations for the year ended December 31, 2001. New Accounting Pronouncements In July 2001, the Financial Accounting Standards Board issued SFAS No. 141. Business Combinations, and SFAS No.142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that the purchase method of 52 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) accounting be used for all business combinations initiated after June 30, 2001 as well as all purchase method business combinations completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet in order to be recognized and reported apart from goodwill, noting that any purchase price allocable to an assembled workforce may not be accounted for separately. SFAS No. 142 will require that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 will also require that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. Mission is required to adopt the provisions of SFAS No. 141 immediately and SFAS No. 142 effective January 1, 2002. As of the date of adoption, Mission's expects to have unamortized goodwill in the amount of $15.1 million and unamortized identifiable intangible assets in the amount of $374,300, all of which will be subject to the transition provisions of SFASs No. 141 and No. 142. Amortization expense related to goodwill was $986,000 for the period ended December 31, 2001. Upon adoption of SFAS No. 142, amortization of goodwill and intangible assets will cease, thereby reducing expenses by approximately $456,000 quarterly. Also, upon adoption of SFAS No. 142, $277,000 of workforce intangible currently recorded as unamortized identifiable intangible assets will be subsumed into goodwill and will not be amortized as it no longer qualifies as a recognizable intangible asset. Because of the extensive effort needed to comply with adopting SFAS No. 141 and No. 142, it is not practicable to reasonably estimate all of the potential impacts of adopting these statements on the Mission's financial statements at the date of this report. In July 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, provides 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. SFAS No. 143 requires that asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Mission will adopt the statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS No. 143 will be reported as a cumulative effect of a change in accounting principle. At this time, Mission cannot reasonably estimate the effect of the adoption of this statement on either financial position or results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which will be effective as of the beginning of 2002. SFAS No. 144 requires that long-lived assets to be disposed of by sale be measured at the lower of the carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. After its effective date, SFAS No. 144 will be applied to those transactions where appropriate. At this time Mission is unable to determine what the future impact of adopting this statement will have on its financial position or results of operations. 53 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 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 with current reporting practices. Prior year financial statements have been restated to present gas plant revenues on a gross basis in accordance with EITF 99-19 "Reporting Revenue Gross as a Principal verses Net as an Agent." The presentation did not impact previously reported net income (loss) or net income (loss) per common share for the periods presented. 3. Acquisitions and Investments During the last three fiscal years, the Company has completed or made the following significant acquisitions and investments: Throughout 1998 and 1999, the Company acquired an interest in Carpatsky Petroleum Incorporated ("Carpatsky"), a Canadian corporation, consisting of common shares, convertible preferred shares and a warrant to acquire additional common shares. The total cost of these investments was $4.6 million. This investment did not give the Company the ability to significantly influence Carpatsky's operations and was accounted for under the cost method. Additionally, the Company made a loan to Carpatsky of $1.0 million under a revolving credit facility established in July 1999 and incurred costs on behalf of Carpatsky of approximately $0.6 million. The Company executed an agreement with Carpatsky effective June 29, 2001 under which it exchanged the interests for a production payment in Carpatsky's producing properties. In the fourth quarter of 2001 due to uncertainties in world markets and declining commodity prices, the related long-term receivable was charged to income as part of impairments on the Statement of Operations. In December 1998, the Company was the successful bidder for the Charapa field in Ecuador. With the successful bid, the Company was awarded a contract for production and exploration of crude oil in the Charapa field. The contract provides the Company with approximately 45% of the crude oil produced above the base production curve. The base production curve is defined as the production profile of the crude oil projected by the Ecuadorian government hydrocarbons subsidiary. Negotiations with the Ecuadorian government took place throughout 1999. The Company officially took over operations of Charapa in January of 2000. In February 2000, the Company took over operations of another Ecuadorian field, the Tiguino field. The contract with the government is similar for both fields. A subsidiary operated the field on behalf of Petroleos Colombianos ("Petrocol"), which had been granted a 25% interest and operatorship by the Ecuadorian government. The Company negotiated with Petrocol and other interest owners throughout 2000 ultimately acquiring 70% and the assignment of operatorship by July 2000. Agreements transferring ownership and operatorship in the Tiguino field were signed by all parties, and the approval was received in August 2001. Two months later the Company sold the subsidiaries that were party to the concessions at a loss of $12.7 million which included a loss on the writedown of a $1.0 million escrow receivable which was estimated to be settled before year end upon resolution of negotiations with the Ecuadorian government. The $1.0 million escrow receivable was written off at year-end due to increased difficulties in negotiating with the Ecuadorian government which made its collection doubtful. See Note 1 under "Oil and Gas Properties: Full Cost Pool" for additional discussion of the sale. 54 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 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 optionholders 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. 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. 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 As of December 31, 2001, the Company is party to a Master Service Agreement dated October 1, 1999, ("Master Service Agreement") and four specific contracts ("Contracts") under which Torch Energy Advisors Incorporated ("Torch") administers certain activities of the Company including oil and gas marketing, operation of oil and gas properties, accounting, risk management, legal and information technology. Previously, the Company was party to six contracts with Torch, but the Land Services Agreement was terminated in early 2001 when the Company brought such function in-house and the Midstream Asset Management Agreement was terminated upon the sale of the gas plant in the fourth quarter of 2001. Neither of these two contract terminations resulted in a termination fee. The Master Services Agreement may be terminated by the Company upon 90 days prior notice, subject to a fee based on the remaining terms of the contracts. The remaining contracts have terms ranging from 6 months to 1 year. Neither the Master Service Agreement nor the Contracts may be terminated by Torch prior to expiration of their initial terms. Since the merger of Bargo Energy Company in May 2001 all of the agreements with Torch were renegotiated except the Corporate Services Agreement. The current contracts have fixed and variable annual fees ranging from $.4 million to $4.9 million. For the periods ended December 31, 2001, 2000, and 1999 related fees paid to Torch amounted to $5.5 million, $4.7 million, and $2.9 million, respectively. Subsequent to December 31, 2001, the Company brought additional functions in-house further reducing the largest agreement with Torch by $0.3 million annually. At the end of 2001 the Company gave notice to Torch that the Company would be terminating the Corporate Services Agreement effective April 2002 and will bring such services in-house. A termination fee stipulated by the terms of the contract of $620,000 has been recognized as part of general and administrative expense in the Statement of Operations for the year ended December 31, 2001. In April 1997, Torch was issued 150,000 shares of the Company's common stock and a warrant, expiring in April 2002, to purchase 100,000 shares at $9.90 per share for advisory services rendered in connection with an acquisition. 55 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) On August 2, 1999, two senior executives left the Company to pursue other opportunities. Mr. J. P. Bryan, a member of the board of directors, then was elected Chairman and CEO effective August 2, 1999. Approximately $1.7 million of severance costs attributable to this management change were incurred in August 1999. Mr. J. P. Bryan served as Chief Executive Officer of Bellwether from August 1999 through May 2000. He continues to be a member of the Mission board of directors. Mr. Bryan is also Senior Managing Director of Torch and owns shares representing 23% of the shares of Torch on a fully diluted basis. Mr. Bryan also owned 1,061,750 shares of Bargo before the merger. Also, Mr. Tim Goff, former Chairman of Bargo and current member of Mission's board of directors, is a non-compensated advisor to Torch regarding potential oil and gas property acquisitions. Pursuant to a separation agreement between the Company and one of the senior executives, 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 is due and payable on August 23, 2002. The loan is secured by 78,323 shares of the Company's common stock. As of December 31, 2001, the outstanding loan balance of $332,872 was reflected in Other Assets on the Balance Sheet, while accrued interest of $55,700 was reflected within accounts receivable and accrued revenues on the Balance Sheet. Sales to subsidiaries of Torch accounted for approximately 32%, 24%, and 22% of fiscal year 2001, 2000 and 1999 oil and gas revenues, respectively. A subsidiary of Torch markets oil and natural gas production from certain oil and gas properties in which the Company owns an interest. Such charges were $417,000, $563,000, and $947,500 in periods ended December 31, 2001, 2000 and 1999, respectively. Prior to the contract revisions the fees were 2% on all marketed production; therefore a savings is reflected in the year 2000 over previous years. Torch has provided services 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, $1.3 million, and $357,800 for these costs in periods ended December 31, 2001, 2000 and 1999, respectively. Torch operates certain oil and gas interests owned by the Company. The Company is charged, on the same basis as other third parties, for all customary expenses and cost reimbursements associated with these activities. Prior to October 1999, Torch retained such reimbursements as part of its compensation. After October 1999, overhead reimbursements are retained by the Company and are reported as reductions to general and administrative expenses. Operator's overhead charged by Torch and retained as compensation for these activities for the period ended December 31, 1999 was $1,153,000. Torch is the operator of the Snyder Gas Plant. In periods ended December 31, 2001, 2000 and 1999, the fees paid by the Company to Torch were $74,000, $96,000, and $73,000, respectively. During the fiscal year 1992, the Company acquired an average 24.4% interest in three mining ventures (the "Mining Venture") from an unaffiliated person for $128,500. At the time of such acquisition, J. P. Bryan, his brother, Shelby Bryan and Robert L. Gerry III, a director of Nuevo Energy Company (the "Affiliated Group"), owned an average 21.5% interest in the Mining Venture. The Company's interest in the Mining Venture increased to 32.5% during 1998 as it paid costs of the venture while the interest of the Affiliated Group decreased. On December 31, 1998, the Company impaired the value of the asset by $465,000, included in the Impairment Expense line of the Statement of Operations, leaving a $10,000 investment. The impairment was taken because Mission believed the venture did not have value above $10,000 without further investments that it did not anticipate would occur. In 1999, the Company invested $273,000 in the Mining Venture, based upon a third party assay showing economically mineable grades of several precious minerals, bringing its recorded investment to 56 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) $283,000 as of December 31, 1999. During 2000, the Company invested $446,000 in the Mining Venture, bringing its recorded investment to $729,000 as of December 31, 2001 for a 40.7% interest. In 2001, the $729,000 accumulated costs, plus $185,000 in core assay and evaluation costs incurred throughout the year were expensed on the Mining Costs line of the Statement of Operations. 5. Stockholders' Equity Common and Preferred Stock The Certificate of Incorporation of the Company authorizes 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. Certain restrictions contained in the Company's loan agreements limit the amount of dividends which 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. In addition to stock options outstanding, the Company has 100,000 warrants outstanding at an exercise price of $9.90 per share. The expiration date for the warrants is April 2002. 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 1999. On May 16, 2001, Bellwether merged with Bargo Energy Company ("Bargo"). The resulting company was renamed Mission Resources Corporation. Contemporaneously with the merger, Bellwether increased its authorized capital stock to 65.0 million shares and amended its 1996 Stock Incentive Plan to increase the number of shares reserved for issuance under the plan by 2.0 million shares. 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. Compensation expense of $43,000 was recognized for an estimate of those employee options that would have expired unexercisable pursuant to its original terms. The expense was calculated as the excess of the price on the merger date over the exercise price of the option. Shareholder Rights Plan In September 1997, the Company adopted a shareholder rights plan to protect Mission's shareholders from coercive or unfair takeover tactics. Under the shareholder rights plan, each outstanding share of Mission's common stock and each share of subsequently issued Mission common stock has attached to it one right. The rights become exercisable if a person or group acquires or announces an intention to acquire beneficial ownership of 15% or more of the outstanding shares of common stock without the prior consent of the Company. When the rights become exercisable each holder of a right will have the right to receive, upon exercise of the right, a number of shares of common stock of the Company which, at the time the rights become exercisable, have a market price of two times the exercise price of the right. The Company 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. 57 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, Year Ended December 31, 2001 2000 -------------------------- ------------------------ Income Shares Per Share Income Shares Per Share -------- ------ --------- ------- ------ --------- Net income (loss)......... $(30,945) $32,208 Earnings (loss) per common share.................... $(30,945) 20,051 $(1.54) $32,208 13,899 $2.32 Effect of dilutive securities: Options & warrants................. -- -- -- 276 -------- ------ ------ ------- ------ ----- Earnings (loss) per common share--diluted........... $(30,945) 20,051 $(1.54) $32,208 14,175 $2.27 ======== ====== ====== ======= ====== ===== Year Ended December 31, 1999 -------------------------- Income Shares Per Share -------- ------ --------- Net income................ $ 8,813 Earnings per common share.................... $ 8,813 13,854 $ 0.64 Effect of dilutive securities: Options & warrants....... -- 42 -------- ------ ------ Earnings per common share--diluted--......... $ 8,813 13,896 $ 0.63 ======== ====== ======
Diluted earnings per share were not calculated since the issuance or conversion of additional securities would have had an antidilutive effect due to the loss in the period. Options and warrants equal to 2,247,000 in 2001, 584,500 in 2000 and 1,181,499 in 1999 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, 1999, 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. 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 year end 2001 167,000 options are available for grants. On May 15, 2000 the Company's president was granted 500,000 options with an exercise price set at the average price for the 30 days prior to the grant date. Such average price was less than the closing price on the grant date. The Company is required to recognize compensation expense, over the vesting period, for the options equal to the difference between the exercise price and the close price of Mission's stock on the grant date. A charge of $536,000 was recorded in May 2000, when one-third of the options vested. The remaining expense was to be charged ratably over the two-year vesting period for the remaining options. Due to the vesting of all outstanding options in connection with the merger on May 16, 2001, the remaining $577,000 expense was recognized as compensation expense in May 2001 bringing the total expense for the year 2001 to $756,000. 58 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, 1998........................ 1,268,500 $4.38 $12.38 Granted........................................... 653,500 $3.34 $ 6.22 Surrendered....................................... (390,000) $3.34 $10.19 Exercised......................................... (4,000) $3.34 $ 3.34 --------- 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 ========= ===== ====== Exercisable at December 31, 2001.................... 2,898,165 $3.34 $12.38 ========= ===== ======
Detail of stock options outstanding and options exercisable at December 31, 2001 follows:
Outstanding Exercisable ------------------------------- ------------------ Weighted Weighted Weighted Average Average Average Remaining Exercise Exercise Range of Exercise Prices Number Life (Years) Price Number Price ------------------------ --------- ------------ -------- --------- -------- 1994 Plan $3.34 to $ 8.25.................... 483,835 4.4 $5.51 483,835 $5.51 1996 Plan $3.34 to $12.38.................. 3,501,000 8.7 $7.47 2,414,330 $7.02 --------- --------- Total................ 3,984,835 2,898,165 ========= =========
The estimated weighted average fair value per share of options granted during 2001, 2000, and 1999 was $3.15, $12.75, and $11.68, 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 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 . For 1999, expected stock price volatility of 93%; a risk free interest rate of 6.5%; and an average expected option life of 10 years 59 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Had compensation expense for stock-based compensation been determined based on the fair value at the date of grant, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except share information):
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2001 2000 1999 ------------ ------------ ------------ Net income (loss) As reported........................ $(30,945) $32,208 $ 8,813 Pro forma.......................... $(35,007) $24,955 $(19,516) Earnings (loss) per share As reported........................ $ (1.54) $ 2.32 $ 0 .64 Pro forma.......................... $ (1.75) $ 1.80 $ (1.41) Diluted earnings (loss) per share As reported........................ $ (1.54) $ 2.27 $ 0 .63 Pro forma.......................... $ (1.75) $ 1.76 $ (1.41)
6. Derivative Instruments and Hedging Activities In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement established standards of accounting for and disclosures of derivative instruments and hedging activities. As amended SFAS No. 133 was effective for fiscal quarters beginning after January 1, 2001. As discussed in Note 1, the Company adopted SFAS No. 133 on January 1, 2001. The Company periodically uses derivative financial instruments to manage oil and gas price risk; generally commodity price swap agreements which provide for the Company to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas or crude oil. Hedging activities decreased revenues by $13.4 million, $24.5 million and $4.0 million for the years 2001, 2000 and 1999, respectively. 60 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The following tables detail the Company's hedges of future production, which were in place at December 31, 2001. Oil Hedges
NYMEX NYMEX BBLS Total Price Price Period Per Day BBLS Type Floor Ceiling ------ ------- --------- ------ ------ ------- Jan. 2002-Mar. 2002.................. 6,000 540,000 Collar $21.50 $31.25 Apr. 2002-Jun. 2002.................. 5,400 491,400 Collar $21.50 $30.25 Jul. 2002-Sep. 2002.................. 4,700 432,400 Collar $21.50 $28.45 Oct. 2002-Dec. 2002.................. 4,000 368,000 Collar $21.50 $27.15 Gas Hedges NYMEX NYMEX MCF Price Price Period Per Day Total MCF Type Floor Ceiling ------ ------- --------- ------ ------ ------- Jan. 2002-Mar. 2002.................. 11,700 1,053,000 Collar $ 3.57 $ 7.00 Apr. 2002-Jun. 2002.................. 10,200 928,200 Collar $ 3.00 $ 6.48 Jul. 2002-Sep. 2002.................. 9,800 901,600 Collar $ 3.00 $ 6.60 Oct. 2002-Dec. 2002.................. 8,500 782,000 Collar $ 3.40 $ 7.00 Jan. 2003-Mar. 2003.................. 10,000 900,000 Collar $ 3.00 $ 4.65 Apr. 2003-Jun. 2003.................. 5,000 455,000 Collar $ 3.00 $ 4.02 Apr. 2003-Jun. 2003.................. 5,000 455,000 Collar $ 3.00 $ 3.97 Jul. 2003-Sep. 2003.................. 10,000 920,000 Collar $ 3.00 $ 4.10 Oct. 2003-Nov. 2003.................. 10,000 920,000 Collar $ 3.00 $ 4.65
As discussed in Note 1, in 2001 the Company began accounting for the collars designated as cash flow hedges in accordance with SFAS No. 133. As a result, changes in the fair value of the cash flow hedges are recognized in Other Comprehensive Income until the hedged item is recognized in earnings, and any change in the fair value due to ineffectiveness is recognized immediately in earnings. For the year 2001, a $4.8 million net gain was recorded as part of interest and other income on the Statement of Operations due to hedge ineffectiveness. The Company expects to transfer the remaining balance of Accumulated Other Comprehensive Income to earnings over the next two years. Mission entered into a gas swap for $4.60 per MCF on 15,000 MCF per day of production from November 2000 through October 2001. This offset hedges previously existing on forecasted production that was sold in late 2000. A related non-cash loss of $8.7 million was recognized in the fourth quarter of 2000, along with a current derivative liability, as this portion of the swap was considered a speculative derivative. The liability was relieved monthly as the swap was settled and is zero at December 31, 2001. Bargo had entered into one derivative, a floor of $21 per Bbl on oil that extended into the year 2001. In adopting SFAS No. 133, it was determined that these derivative contracts would be marked to market. The Company acquired these contracts at the time of the merger. The contract terminated in December 2001; therefore, no related asset or liability remains. Effective September 22, 1998, the Company entered into an eight and one- half year interest rate swap agreement with a notional value of $80 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are redetermined for a six-month period each April 1 and October 1. The interest rate swap did not qualify for hedge 61 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) accounting under SFAS No. 133 and is therefore marked to market each quarter. For the year 2001, a net gain of $332,000 was recorded as a reduction of interest expense related to the change in the fair value of the interest rate swap. 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, 2001 and 2000 (in thousands).
December 31, 2001 December 31, 2000 ---------------------- ---------------------- 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) $ (25,450) $(25,450) Senior Subordinated Notes, excluding $1.7 million unamortized premium on $125 million bonds................... $(225,000) $(202,500) $(100,000) $(89,440)
8. Long-Term Debt Long-term debt is comprised of the following at December 31, 2001 and 2000 (in thousands):
December 31, December 31, 2001 2000 ------------ ------------ Bank credit facility............................. $ 35,000 $ 25,450 10 7/8% Senior Subordinated Notes................ 225,000 100,000 -------- -------- Subtotal......................................... 260,000 125,450 Premium on $125 million Senior Subordinated Notes........................................... 1,695 -- -------- -------- Long-term debt................................... $261,695 $125,450 ======== ========
Debt maturities by fiscal year are as follows (amounts in thousands): 2002................................................................ $ -- 2003................................................................ $ -- 2004................................................................ $ 35,000 2005................................................................ $ -- 2006................................................................ $ -- Thereafter.......................................................... $225,000 -------- $260,000 ========
In April 1997, the Company entered into a senior revolving unsecured credit facility ("Senior Credit Facility") in an amount up to $90.0 million, with a borrowing base to be re-determined semi-annually, and a maturity date of November 5, 2003. On May 20, 1999 the borrowing base was re-determined to be $55.0 million. Subsequent amendments reflecting the impact of the property sales in 2000 have reduced the borrowing base to $34.5 million at December 31, 2000. At December 31, 2000, there was $24.5 million in borrowings outstanding under the Senior Credit Facility. 62 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Under the Senior Credit Facility, the Company could elect an interest rate based either on a margin plus London Interbank Offered Rate ("LIBOR") or the higher of the prime rate or the sum of 0.5% of 1% plus the Federal Funds Rate. For LIBOR borrowings, the interest rate will vary from LIBOR plus 1.0% to LIBOR plus 3.5% based upon the borrowing base usage. The Senior Credit Facility contains various covenants including certain required financial measurements for current and interest ratios and consolidated tangible net worth. As of December 31, 2000 the Company was in compliance with all debt covenants. In addition, the Senior Credit Facility contains the following limitations: . Mission and its subsidiaries will not sell all or substantially all of their assets to another person, . none of Mission or its subsidiaries will incur additional indebtedness with the exception of permitted indebtedness, . the indebtedness of Mission's subsidiaries will not exceed 10% of consolidated tangible net worth (indebtedness from subsidiaries to Mission or guarantors is permitted), . none of Mission or its subsidiaries will make any restricted payments or restricted investments unless no default exists under the Senior Credit Facility and all such restricted payments and investments made since closing do not exceed the sum of (A) $5 million plus (B) 25% consolidated net income (less 100% of losses) plus (C) net cash proceeds of non-redeemable stock, provided, there are no payments made on permitted subordinated debt prior to stated maturity. On May 16, 2001, concurrent with the Bargo merger previously discussed, the Senior Credit Facility was replaced with a $200.0 million credit facility ("Credit Facility") with an initial borrowing base of $185.0 million. The borrowing base is determined from time to time by lenders based on the Company's reserves and other factors deemed relevant by the lenders. Such borrowing base was adjusted for acquisitions and financing activities, primarily the issuance of senior subordinated notes, and at December 31, 2001 was $125.0 million with $90.0 million available. The interest rate on borrowings is determined based upon the Company's credit rating and borrowing base utilization. Interest can be either Prime plus a margin of up to 1% or LIBOR plus a margin of 1.5% to 2.5%. The Credit Facility contains various covenants including certain required financial measurements for current ratio, ratio of total debt to EBITDAX and interest coverage ratio. Restrictions are placed on debt, liens, dividends, leases and capital spending in foreign operations. On December 31, 2001, $35.0 million was outstanding under the Credit Facility and the Company was in compliance with its covenants under the Credit Facility. Mission met with its lenders on March 5, 2002 to discuss the re- determination of the borrowing base applicable to the Credit Facility and effective April 1, 2002 the borrowing base has been redetermined at $100.0 million. Mission also requested amendments to its debt covenants in response to the late 2001 and early 2002 decline in prices. Mission's debt covenants for the four quarters of 2002 were amended with the required ratio of total debt to EBITDAX being increased and the required interest coverage ratio being reduced Borrowings through March 15, 2001, were $45.5 million outstanding under the Credit Facility. In April 1997, the Company issued $100.0 million of 10 7/8% Senior Subordinated Notes that mature April 1, 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 premium is included in long-term debt on the Balance Sheet. It will be amortized as a reduction of interest expense over the life of the notes so that the effective interest rate on these additional bonds is 10.5%. For the year 2001, approximately $200,000 of the premium had been amortized. 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 63 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 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, restricted payments, transactions with affiliates, liens, guarantees of indebtedness by subsidiaries, dividends and other payment restrictions affecting restricted subsidiaries, issuance and sales of restricted subsidiary stock, disposition of proceeds of asset sales, and restrictions on mergers, and consolidations or sales of assets. 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, 2001 2000 1999 ------------ ------------ ------------ Current Federal............................ $ -- $ 67 $ (425) State.............................. 595 18 10 Deferred Federal............................ $(10,488) $(13,506) $(2,994) Foreign............................ ( 300) 300 -- State.............................. 1,138 899 255 -------- -------- ------- Total income tax benefit............. $ (9,055) $(12,222) $(3,154) ======== ======== =======
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2001 and 2000 is as follows:
December 31, December 31, 2001 2000 ------------ ------------ Net operating loss carryforwards.................. $ 12,487 $10,091 Percentage depletion carryforwards................ 279 271 Alternative minimum tax credit carryforwards...... 742 752 Property, plant and equipment..................... -- 3,087 State income taxes................................ 2,134 1,138 Impairment of interest in Carpatsky............... 2,186 -- Other............................................. 1,689 -- -------- ------- Total gross deferred tax assets................... 19,517 15,339 -------- ------- Less valuation allowance.......................... (4,320) -- -------- ------- Net deferred income tax assets.................... 15,197 15,339 -------- ------- Property, plant and equipment..................... (45,143) -- Taxes in SFAS No. 133 balance sheet account....... (1,231) -- Foreign income taxes.............................. -- (198) -------- ------- Total deferred income tax liability............... (46,374) (198) -------- ------- Net deferred income tax asset (liability)......... $(31,177) $15,141 ======== =======
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 64 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 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 in Carpatsky, as 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. Therefore, the valuation allowance has been increased by $4.3 million for the year ending December 31, 2001. 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. 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 1999. 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, 2001 2000 1999 ------------ ------------ ------------ Statutory federal income tax rate... 35.0% 34.0% 34.0% Increase (decrease) in tax rate resulting from: State income taxes, net of federal benefit.......................... (1.3%) 3.0% 3.1% Foreign income taxes, net of federal benefit.................. 0.5% 1.0% -- Non-deductible travel and entertainment...................... (0.1%) 0.1% 0.2% Non-deductible goodwill amortization....................... (0.9%) -- -- Other............................... -- -- (.8%) Change in valuation allowance....... (8.9%) (99.3%) (92.2%) ---- ----- ----- 24.3% (61.2%) (55.7%) ==== ===== =====
The Company issued 9.5 million shares of its common stock on May 16, 2001 in its acquisition of Bargo Energy Company. The Company issued 3.4 million shares of its common stock on July 20, 1994. As a result of the 1994 common stock issuance, the Company underwent an ownership change. Therefore, the Company's ability to use a portion of its net operating loss ("NOL") carryforwards for federal income tax purposes is subject to limitations. 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, 2001, the Company had net operating loss carryforwards of approximately $35.7 million, which will expire in future years beginning in 2002. 65 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 10. Commitments and Contingencies Lease Commitments The minimum future payments under the terms of the Company's office space operating leases are as follows:
Year Ended December 31 ($ in thousands) -------- --------------- 2002 819 2003 597 2004 601 2005 601 2006 601
Rent expense was $551,000, $509,000 and $16,023 in 2001, 2000 and 1999. Contingencies The Company has been named as a defendant in certain lawsuits incidental to its business. Management does not believe that the outcome of such litigation will have a material adverse impact on the Company. Mission is a defendant in Cause No. C-1313-97-D; Garza Energy Trust, et al. V. Coastal Oil and Gas Corporation, et al.; in the 206th Judicial District Court of Hidalgo County, Texas. The lawsuit addresses a 748.2 acre gas field located in the Jeffress East Field and/or Jeffress S.E., Vicksberg Field, Hidalgo County, Texas. Plaintiffs are royalty interest owners in these properties and have made a number of claims including failure to properly develop, drainage, subsurface trespass, improper payment of royalties, and failure to properly market production. A modified judgement was signed in mid- December 2001. The judgement awarded the Plaintiff damages of $250,000 against Mission. Mission has accrued $250,000 as a reduction to earnings reported for the period ended December 31, 2001. 11. Restructuring During the year the Company took several steps planned to enhance its asset base, improve its cost structure and boost its competitive position in the business environment presented by low oil and gas prices. Among those steps were the reduction of staff by almost 50% and the termination of the Company's administrative, accounting, information technology services and field operations outsourcing contracts. The Company recorded $2.1 million associated with these plans. The charge was included in general and administrative expenses. During 2002, the Company has paid termination benefits of approximately $600,000 associated with the termination of 17 employees and charged this against the accrued liability. The remaining $1.5 million accrued liability is expected to be paid in the next few months. 66 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 12. Selected Quarterly Financial Data (amounts in thousands, except per share data) (Unaudited):
Quarter Ended --------------------------------------------- June December 31, September 30, 30, March 31, 2001 2001 2001 2001 ------------ ------------- ------- --------- Revenues..................... $ 32,522 $40,497 $35,243 $33,815 Operating income (loss)...... $(39,099) $ 1,429 $(9,432) $ 9,869 Net income (loss)............ $ 29,260 $ 693 $(6,007) $ 3,629 Earnings (loss) per common share....................... $ (1.24) $ 0.03 $ (0.32) $ 0.46 Earnings (loss) per common shares--diluted............. $ (1.24) $ 0.03 $(0.32) $ 0.44 Quarter Ended --------------------------------------------- June December 31, September 30, 30, March 31, 2000 2000 2000 2000 ------------ ------------- ------- --------- Revenue...................... $ 35,924 $31,526 $26,669 $25,162 Operating income............. $ 680 $ 8,639 $ 5,011 $ 5,656 Net income................... $ 432 $ 5,357 $ 3,029 $23,390 Earnings per common share.... $ 0.03 $ 0.38 $ 0.22 $ 1.69 Earnings per common share-- diluted..................... $ 0.03 $ 0.37 $ 0.21 $ 1.67
The income in the quarter ended March 31, 2000 reflects the recognition of a $19.8 million tax asset based upon increased future net reserves. 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
67 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 14. Segment Reporting Through mid-2001, the Company's operations are concentrated primarily in three segments: exploration and production of oil and natural gas in the United States, in Ecuador and gas plants. The assets in Ecuador and two gas plants were sold in 2001.
Year Ended December 31, --------------------------- 2001 2000 1999 -------- -------- -------- Sales to unaffiliated customers: Oil and gas--US................................ $131,358 $107,938 $ 68,264 Oil and gas--Ecuador........................... 1,877 4,315 -- Gas plants..................................... 4,456 6,070 3,830 -------- -------- -------- Total sales.................................. 137,691 118,323 72,094 Interest and other income...................... 4,386 957 1,335 -------- -------- -------- Total revenues............................... 142,077 119,280 73,429 ======== ======== ======== Operating profit (loss) before income taxes: Oil and gas--US................................ $38, 549 $ 40,983 $ 22,570 Oil and gas--Ecuador........................... (1,698) 719 (17) Gas plants..................................... 2,338 3,393 1,464 Gain on gas plant sale......................... 1,124 -- -- -------- -------- -------- $ 40,313 $ 45,095 $ 24,017 Unallocated corporate expenses................. 10,998 9,734 6,513 Interest expense............................... 23,664 15,375 11,845 Mining venture costs........................... 914 -- -- Loss on sale of Ecuador interests.............. 12,724 -- -- Impairment expense............................. 27,057 -- -- Uncollectible gas revenue...................... $ 2,189 -------- -------- -------- Operating profit (loss) before income taxes.... $(37,233) $ 19,986 $ 5,659 ======== ======== ======== Identifiable assets: Oil and gas--US................................ $379,738 $125,586 $123,686 Oil and gas--Ecuador........................... -- 12,243 1,246 Gas plants..................................... -- 11,107 11,641 -------- -------- -------- $379,738 $148,936 $136,573 Corporate assets and investments............... 68,026 72,609 35,188 -------- -------- -------- Total........................................ $447,764 $221,545 $171,761 ======== ======== ======== Capital expenditures: Oil and gas--US................................ $ 68,048 $ 76,242 $ 56,793 Oil and gas--Ecuador........................... 4,151 12,130 -- Gas plants..................................... 1,047 677 369 -------- -------- -------- $ 73,246 $ 89,049 $ 57,162 ======== ======== ======== Depreciation, depletion amortization and impairments: Oil and gas--US................................ $ 41,895 $ 30,356 $ 22,643 Oil and gas--Ecuador........................... 504 745 -- Gas plants..................................... 1,025 1,211 1,159 -------- -------- -------- $ 43,424 $ 32,312 $ 23,802 ======== ======== ========
68 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 15. Supplemental Information--(Unaudited) Oil and Gas Producing Activities: Included herein is information with respect to oil and gas acquisition, exploration, development and production activities, which is based on estimates of year-end oil and gas reserve quantities and estimates of future development costs and production schedules. Reserve quantities and future production are based primarily upon reserve reports prepared by the independent petroleum engineering firm Ryder Scott Company for the years ended December 31, 2000 and 1999. 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. 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 Statement of Financial Accounting Standards 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. 69 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Costs Incurred (in thousands)
Year Ended December 31, ------------------------ 2001 2000 1999 -------- ------- ------- United States: Property acquisition: Proved properties*................................ $280,281 $ 5,065 $22,428 Unproved properties............................... 4,100 -- 2,406 Exploration....................................... 12,489 13,139 14,052 Development: Proved developed properties....................... 25,609 41,615 15,500 Proved undeveloped properties..................... 6,462 16,423 1,352 -------- ------- ------- $328,941 $76,242 $55,738 -------- ------- ------- Ecuador: Property acquisition: Proved properties................................. $ 249 $ 2,013 $ 651 Unproved properties............................... -- -- 404 Development: Proved developed properties....................... 3,902 10,117 -- Proved undeveloped properties..................... -- -- -- -------- ------- ------- $ 4,151 $12,130 $ 1,055 -------- ------- ------- Worldwide: Property acquisition: Proved properties................................. $280,530 $ 7,078 $23,079 Unproved properties............................... 4,100 -- 2,810 Exploration....................................... 12,489 13,139 14,052 Development: Proved developed properties....................... 29,511 51,732 15,500 Proved undeveloped properties..................... 6,462 16,423 1,352 -------- ------- ------- $333,092 $88,372 $56,793 ======== ======= =======
-------- * 2001 total includes $56.6 million of deferred taxes related to the Bargo merger. 70 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Capitalized costs (in thousands):
Year Ended December 31, -------------------- 2001 2000 --------- --------- United States: Proved properties........................................ $ 738,375 $ 410,048 Unproved properties...................................... 15,530 11,360 --------- --------- Total capitalized costs................................ 753,905 421,408 Accumulated depreciation, depletion, Amortization and impairment............................................ (374,167) (295,822) --------- --------- Net capitalized costs................................ $ 379,738 $ 125,586 --------- --------- Ecuador: Proved properties........................................ $ -- $ 12,988 Unproved properties...................................... -- -- --------- --------- Total capitalized costs................................ 12,988 Accumulated depreciation, depletion, amortization and impairment............................................ -- (745) --------- --------- Net capitalized costs................................ $ -- $ 12,243 --------- --------- Worldwide: Proved properties........................................ $ 738,375 $ 423,036 Unproved properties...................................... 15,530 11,360 --------- --------- Total capitalized costs................................ 753,905 434,396 Accumulated depreciation, depletion, amortization and impairment............................................ (374,167) (296,567) --------- --------- Net capitalized costs................................ $ 379,738 $ 137,829 ========= =========
71 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Results of operations for producing activities (in thousands):
Year Ended December 31, 2001 --------------------------- U.S. 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 ======== ======= ========
Results of operations for producing activities (in thousands):
Year Ended December 31, 2000 ------------------------------ U.S. 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 ======== ====== ======== Year Ended December 31, 1999(1) ------------ Revenues from oil and gas producing activities.. $ 68,264 Production costs................................ 21,532 Transportation costs............................ 316 Income tax...................................... 8,820 Depreciation, depletion and amortization........ 22,643 -------- Results of operations from producing activities (excluding corporate overhead and interest costs)......................................... $ 14,953 ========
-------- (1) Ecuador activities did not commence production until 2000; therefore, no prior year information for international operations is disclosed. 72 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, 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 are pursuant to a contract with the Ecuadorian government under which the Company does not own the reserves but has a contractual right to produce the reserves and receive revenues. 73 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 are pursuant to a contract with the Ecuadorian government under which the Company does not own the reserves but has a contractual right to produce the reserves and receive revenues. 74 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended December 31, 1999 ----------------------- Oil NGL Gas Description (MBBL) (MBBL) (MMCF) ----------- ------ ------ ------- United States: Proved reserves at beginning of year................... 8,489 1,573 111,585 Revisions of previous estimates........................ 2,671 798 (767) Extensions and discoveries............................. 499 -- 11,636 Production............................................. (1,831) (249) (18,965) Sales of reserves in-place............................. (262) (60) (6,754) Purchase of reserves in-place.......................... 1,261 7 33,344 ------ ----- ------- Proved reserves at end of year......................... 10,827 2,069 130,079 ====== ===== ======= Proved developed reserves-- Beginning of year.................................... 8,021 1,554 106,253 ====== ===== ======= End of year.......................................... 9,990 2,032 108,491 ====== ===== ======= Ecuador: (1) Purchase of reserves in-place.......................... 3,884 -- -- ------ ----- ------- Proved reserves at end of year......................... 3,884 -- -- ====== ===== ======= Proved developed reserves-- Beginning of year.................................... -- -- -- ====== ===== ======= End of year.......................................... 245 -- -- ====== ===== ======= Worldwide: Proved reserves at beginning of year................... 8,489 1,573 111,585 Revisions of previous estimates........................ 2,671 798 (767) Extensions and discoveries............................. 499 ---- 11,636 Production............................................. (1,831) (249) (18,965) Sales of reserves in-place............................. (262) (60) (6,754) Purchase of reserves in-place.......................... 5,145 7 33,344 ------ ----- ------- Proved reserves at end of year......................... 14,711 2,069 130,079 ====== ===== ======= Proved developed reserves-- Beginning of year.................................... 8,021 1,554 106,253 ====== ===== ======= End of year.......................................... 10,235 2,032 108,491 ====== ===== =======
-------- (1) The Company's Ecuador reserves are pursuant to a contract with the Ecuadorian government under which the Company does not own the reserves but has a contractual right to produce the reserves and receive revenues. 75 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, --------------------------------- 2001 2000 1999 ---------- ---------- --------- United States: Future cash flow............................. $1,200,145 $ 950,121 $ 535,605 Future production costs...................... (502,083) (203,464) (202,800) Future income taxes.......................... (112,364) (183,139) (23,234) Future development costs..................... (97,644) (36,874) (54,034) ---------- ---------- --------- Future net cash flows........................ 488,054 526,644 255,537 10% discount factor.......................... (192,483) (133,062) (63,933) ---------- ---------- --------- Standardized future net cash flows........... $ 295,571 $ 393,582 $ 191,604 ========== ========== ========= Ecuador: Future cash flow............................. $ -- $ 174,632 $ 88,089 Future production costs...................... -- (60,899) (34,534) Future income taxes.......................... -- (37,793) (9,860) Future development costs..................... -- (27,595) (13,273) ---------- ---------- --------- Future net cash flows........................ -- 48,345 30,422 10% discount factor.......................... -- (18,835) (17,138) ---------- ---------- --------- Standardized future net cash flows........... $ -- $ 29,510 $ 13,284 ========== ========== ========= Worldwide: Future cash flow............................. $1,200,145 $1,124,753 $ 623,694 Future production costs...................... (502,083) (264,363) (237,334) Future income taxes.......................... (112,364) (220,932) (33,094) Future development costs..................... (97,644) (64,469) (67,307) ---------- ---------- --------- Future net cash flows........................ 488,054 574,989 285,959 10% discount factor.......................... (192,483) (151,897) (81,071) ---------- ---------- --------- Standardized future net cash flows........... $ 295,571 $ 423,092 $ 204,888 ========== ========== =========
76 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands of dollars):
Year Ended December 31, 2001 ------------------------------ United World Ecuador States Wide -------- --------- --------- Standardized measure--beginning of year........ $ 29,510 $ 393,582 $ 423,092 Sales, net of production costs................. 1,194 (83,151) (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..................... 18,577 30,994 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... 3,736 21,584 25,320 Revisions of quantity estimates................ -- 18,376 18,376 Accretion of discount.......................... 2,950 39,358 42,308 Sales of reserves in-place..................... (53,017) (89,139) (142,156) Changes in production rates and other.......... (2,950) 37,512 34,562 -------- --------- --------- Standardized measure--end of year.............. $ -- $ 295,571 $ 295,571 ======== ========= ========= Year Ended December 31, 2000 ------------------------------ United World Ecuador States Wide -------- --------- --------- Standardized measure--beginning of year........ $ 13,284 $ 191,604 $ 204,888 Sales, net of production costs................. (1,500) (80,244) (81,744) Purchases of reserves in-place................. 28,389 -- 28,389 Net change in prices and production costs...... (23,174) 375,242 352,068 Net change in income taxes..................... (14,430) (113,444) (127,874) Extensions, discoveries and improved recovery, net of future production and development costs......................................... -- 56,283 56,283 Changes in estimated future development costs.. (1,990) (4,942) (6,932) Development costs incurred during the period... 4,329 31,095 35,424 Revisions of quantity estimates................ (6,787) (46,271) (53,058) Accretion of discount.......................... 1,329 19,160 20,489 Sales of reserves in-place..................... -- (34,697) (34,697) Changes in production rates and other.......... 30,060 (204) 29,856 -------- --------- --------- Standardized measure--end of year.............. $ 29,510 $ 393,582 $ 423,092 ======== ========= =========
77 MISSION RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended December 31, 1999 --------------------------- United World Ecuador States Wide ------- -------- -------- Standardized measure--beginning of year.......... $ -- $115,980 $115,980 Sales, net of production costs................... -- (50,430) (50,430) Purchases of reserves in-place................... 17,431 40,488 57,919 Net change in prices and production costs........ -- 40,736 40,736 Net change in income taxes....................... (4,147) -- (4,147) Extensions, discoveries and improved recovery, net of future production and development costs.. -- 23,497 23,497 Changes in estimated future development costs.... -- (3,304) (3,304) Development costs incurred during the period..... -- 8,930 8,930 Revisions of quantity estimates.................. -- 20,565 20,565 Accretion of discount............................ -- 11,598 11,598 Sales of reserves in-place....................... -- (6,575) (6,575) Changes in production rates and other............ -- (9,881) (9,881) ------- -------- -------- Standardized measure--end of year................ $13,284 $191,604 $204,888 ======= ======== ========
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 $19.76, $26.80, and $25.60 per barrel and $2.73, $9.52, and $2.33 per MMBTU, for December 31, 2001, 2000, and 1999, 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 and $370,000 as of December 31, 2001 and 1999, respectively. Including the tax effected impact of hedging on discounted future cash flows would have decreased discounted future net cash flows by approximately $35.7 million as of December 31, 2000. 78 MISSION RESOURCES CORPORATION AND SUBSIDIARIES PART III Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None 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, 2001. 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, 2001. Such information is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2001. 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, 2001. Such information is incorporated herein by reference. PART IV Item 14. 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 dated January 26, 2001). 3. Exhibits 3.1 Certificate of Incorporation of Mission Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement No. 33-76570) 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 for the fiscal year ended June 30, 1997) 3.3 Certificate of Designation, Preferences and Rights of Series A Preferred Stock (incorporated by reference to Exhibit 1 to the Company's Registration Statement on Form 8-A dated September 19, 1997.)
79 3.4 By-laws of Mission Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement No. 33-76570) 3.5 Amendment to Article II, Section 2.2 of Mission Resources Corporation's Bylaws (incorporated by reference to Exhibit 3.5 to the Company's Annual Report on Form 10-K for the transition period ended December 31, 1997) 3.6 Amendment to Mission Resources Corporation's bylaws adopted on March 27, 1998 (incorporated by reference to Exhibit 3.6 to the Company's Annual Report on Form 10-K for the transition period ended December 31, 1997) 4.1 Specimen Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1, File No. 33-76570) 4.2 The Company's 1996 Stock Incentive Plan (incorporated by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1, File No. 33-21813) 4.3 Indenture dated April 9, 1997 among the Company, a Subsidiary Guarantor and Bank of Montreal Trust Company (incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-1, Registration No. 33-21813) 4.4 First Supplemental Indenture dated April 21, 1997 among the Company, Odyssey Petroleum Company, Black Hawk Oil Company, 1989-I TEAI Limited Partnership and Bank of Montreal Trust Company, as Trustee (incorporated by reference to Exhibit 99.2 on the Company's Form 8-K Current Report filed on April 23, 1997) 4.5 Shareholders Rights Agreement between the Company and American Stock Transfer & Trust Company (incorporated herein by reference to the Company's Registration Statement on Form 8-A as filed with the Securities and Exchange Commission on September 19, 1997) 4.6 Warrant to Torch Energy Dated April 9. 1997 (incorporated by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 1997) 4.7 Indenture dated May 29, 2001 among Mission Resources Corporation, the Subsidiary Guarantors named therein and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed on July 27, 2001) 4.8 Exchange and Registration Rights Agreement dated as of May 29, 2001 among Mission Resources Corporation, the Subsidiary Guarantors listed on Schedule 1 thereto, JPMorgan Securities Inc and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 4.3 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) 10.2 Acquisition Agreement dated March 31, 1997 among Mission Resources Corporation, Program Acquisition Company and the other parties thereto. (incorporated by reference to Exhibit 2.2 of the Company's Registration Statement on Form S-1 (Registration No. 333-21813) filed on April 3, 1997) 10.3 Credit Agreement dated April 21, 1997 among the Company, Odyssey Petroleum Company, Black Hawk Oil Company, 1989-I TEAI Limited Partnership, Morgan Guarantee Trust Company of New York, as administrative Agent, and certain banking institutions (incorporated by reference to the Company's Form 8-K Current Report as filed with the Commission on April 23, 1997). 10.4 Purchase and Sale Agreement dated June 9, 1997 among Mission Resources Corporation, Black Hawk Oil Company, 1988-II TEAI Limited Partnership, 1989-I TEAI Limited Partnership, TEAI Oil and Gas Company, and the other parties thereto as Sellers, and Jay Resources Corporation as Buyer (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 1997)
80 10.5 Employment contract dated June 1, 1998 between the Company and J. Darby Sere' (incorporated by reference to Exhibit 10.1 to the Company's 10-Q for the quarter ended June 30, 1998) 10.6 Employment contract dated June 1, 1998 between the Company and William C. Rankin (incorporated by reference to Exhibit 10.2 to the Company's Report on Form 10-Q for the quarter ended June 30, 1998) 10.7 Purchase and Sale Agreement dated June 11, 1999 between Bellwether Exploration Company as Buyer and Energen Resources MAQ, Inc. as Seller (incorporated by reference to Exhibit 10.15 to the Company's Report on Form 10-Q for the quarter ended June 30, 1999) 10.8 Separation contract dated August 9, 1999 between the Company and J. Darby Sere' (incorporated by reference to Exhibit 10.16 to the Company's Report on Form 10Q for the quarter ended June 30, 1999) 10.9 Separation contract dated August 9, 1999 between the Company and William C. Rankin (incorporated herein by reference to Exhibit 10.17 to the Company's Report on Form 10-Q for the quarter ended June 30, 1999) 10.10 Employment Contract dated August 1, 1999 between the Company and J.P. Bryan (incorporated herein by reference to Exhibit 10.18 to the Company's Report on Form 10-Q for the quarter ended September 30, 1999) 10.11 Securities Purchase Agreement dated December 29, 1999 by and between the Company and Carpatsky Petroleum, Inc.--(incorporated by references to Exhibit 11.14 to the Company's Annual Report on Form 10-K for the year ended December 31,1999) 10.12 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 references to Exhibit 11.15 to the Company's Annual Report on Form 10-K for the year ended December 31,1999) 10.13 Contract for the Production of Crude Oil and Additional Hydrocarbon Exploration in the Charapa Marginal Field of Petroecuador between the Company in Consortium with Tecnipetrol, Inc. and the Ecuadorian State Oil Company, Petroecuador --(incorporated by references to Exhibit 11.16 to the Company's Annual Report on Form 10-K for the year ended December 31,1999) 10.14 Master Service Agreement between the Company and Tecnie S.A.C. dated November 1, 1999----(incorporated by references to Exhibit 10.17 to the company's annual report on form 10-K for the year ended December 31,1999) 10.15 Employment contract dated May 15, 2000 between the Company and Douglas G. Manner (incorporated by reference to Exhibit 10.20 to the Company's Report on Form 10-Q for the quarter ended June 30, 2000) 10.16 Separation agreement dated January 1, 2001 between the Company and Robert J. Bensh--(incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K/A for the year ended December 2000) 10.17 Employment contract dated January 15, 2001 between the Company and Kent Williamson--(incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K/A for the year ended December 2000) 10.18 Contract for Crude Oil Production and Additional Exploration of Hydrocarbons in the Marginal Field Tiguino (incorporated by reference to Exhibit 10.19 to the Company's Proxy Statement filed April 24, 2001) 10.19 Credit Agreement dated May 16, 2001 among Mission Resources Corporation 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--included herewith
81 11.22 Form of Voting Agreement (incorporated by reference to the Company's 8-K dated January 26, 2001) 21.1 Subsidiaries of Mission Resources Corporation--included herewith 23 Consents of experts: 23.2 Consent of Ryder Scott Company--included herewith 23.3 Consent of KPMG LLP--included herewith 23.4 Consent of Netherland Sewell & Associates, Inc.--included herewith 23.5 Consent of T.J. Smith & Company, Inc.--included herewith
82 GLOSSARY OF OIL AND GAS TERMS Terms used to describe quantities of oil and natural gas . Bbl--One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons. . Bcf--One billion cubic feet of natural gas. . Bcfe--One billion cubic feet of natural gas equivalent. . BOE--One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil. . MBbl--One thousand Bbls. . Mcf--One thousand cubic feet of natural gas. . MMBbl--One million Bbls of oil or other liquid hydrocarbons. . MMcf--One million cubic feet 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--The Company's gross wells or gross acres represent the total number of wells or acres in which the Company 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 the Company 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 pre-tax future net cash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and gas production attributable to the proved reserves estimated in its independent engineer's reserve report for the prices it received for the production on the date of the report, unless it had a contract to sell the production for a different price. The Company also assumes 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 the Company's proved reserves. . Pre-tax 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. The Company discloses the discounted present value without deducting estimated income taxes to provide what it believes is a better basis for comparison of its reserves to the producers who may have different tax rates. Terms used to classify our reserve quantities . Proved reserves--The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. 83 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 which describe the cost to acquire the Company's reserves . Finding costs--The Company's finding costs compare the amount the Company spent to acquire, explore and develop its oil and gas properties, explore for oil and gas and to drill and complete wells during a period, with the increases in reserves during the period. This amount is calculated by dividing the net change in the Company's evaluated oil and property costs during a period by the change in proved reserves plus production over the same period. The Company's finding costs as of December 31 of any year represent the average finding costs over the three-year period ending December 31 of that year. Terms which 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, 2001, 2000 or 1999 equal 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 the Company's 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, 84 a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land. . Working interest--A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property. Terms used to describe seismic operations . Seismic data--Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which 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. The Company's 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. . No. 6 fuel oil (Bunker)--No. 6 fuel oil is a heavy residual fuel oil used by ships, industry, and for large-scale heating installations. . 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. 85 MISSION RESOURCES CORPORATION AND SUBSIDIARIES SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Company and in the capacities and on the dates indicated. MISSION RESOURCES CORPORATION /s/ Douglas Manner By: _________________________________ Douglas G. Manner Chief Executive Officer & Chairman Dated March 28, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Signatures Title Date ---------- ----- ---- /s/ Jonathon Clarkson President--Chief Financial March 28, 2002 ______________________________________ Officer Jonathon Clarkson /s/ Ann Kaesermann Vice President--Chief March 28, 2002 ______________________________________ Accounting Officer Ann Kaesermann /s/ July Allen Director March 28, 2002 ______________________________________ July Allen /s/ J. P. Bryan Director March 28, 2002 ______________________________________ J. P. Bryan Director ______________________________________ Tim J. Goff /s/ D. Martin Phillips Director March 28, 2002 ______________________________________ D. Martin Phillips /s/ Robert Rooney Director March 28, 2002 ______________________________________ Robert R. Rooney
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