10-K 1 h23177e10vk.txt MISSION RESOURCES CORPORATION - DECEMBER 31, 2004 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 0-9498 MISSION RESOURCES CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 76-0437769 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1331 LAMAR, SUITE 1455, 77010-3039 HOUSTON, TEXAS (Zip Code) (Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 495-3000 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Common Stock, $0.01 par value Series A Preferred Stock Purchase Rights Indicate by check mark whether the registrant (1) has filed all reports required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ] The aggregate market value of the voting stock held by non-affiliates of the registrant at June 30, 2004 was approximately $136,522,433. As of March 7, 2005, the number of outstanding shares of the registrant's common stock was 41,530,671. Documents Incorporated by Reference: Portions of the registrant's annual proxy statement, to be filed within 120 days after December 31, 2004, are incorporated by reference into Part III of this Form 10-K. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- MISSION RESOURCES CORPORATION AND SUBSIDIARIES ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2004 TABLE OF CONTENTS
PAGE NUMBER ------ PART I Items 1. & 2. Business and Properties..................................... 2 Item 3. Legal Proceedings........................................... 25 Item 4. Submission of Matters to a Vote of Security Holders......... 25 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities........... 25 Item 6. Selected Financial Data..................................... 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................... 27 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................ 46 Item 8. Financial Statements and Supplementary Data................. 48 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................... 92 Item 9A. Controls and Procedures..................................... 92 Item 9B. Other Information........................................... 92 PART III Item 10. Directors and Executive Officers of the Registrant.......... 92 Item 11. Executive Compensation...................................... 92 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................. 92 Item 13. Certain Relationships and Related Transactions.............. 93 Item 14. Principal Accounting Fees and Services...................... 93 PART IV Item 15. Exhibits, Financial Statement Schedules..................... 93
1 PART I FORWARD LOOKING STATEMENTS This annual report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). All statements other than statements of historical fact are forward-looking statements. Forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our estimate of the sufficiency of existing capital sources, our highly leveraged capital structure, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business. Although we believe that in making such forward-looking statements our expectations are based upon reasonable assumptions, such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. We cannot assure you that the assumptions upon which these statements are based will prove to have been correct. When used in this Form 10-K, the words "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Management's Discussions and Analysis of Financial Condition and Results of Operations," "Risk Factors" and elsewhere in this Form 10-K. You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. Before you invest in our common stock, you should be aware that the occurrence of any of the events described in "Management's Discussions and Analysis of Financial Condition and Results of Operations," "Risk Factors" and elsewhere in this Form 10-K could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common stock could decline, and you could lose all or part of your investment. We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we undertake no obligation to update any of the forward-looking statements in this Form 10-K after the date of this Form 10-K. As used in this annual report, the words "we," "our," "us," "Mission" and the "Company" refer to Mission Resources Corporation, its predecessors and subsidiaries, except as otherwise specified. Terms specific to the oil and gas industry may be used in this Form 10-K. For explanation of technical terms, refer to the "Glossary of Oil and Gas Terms" at the end of this Form 10-K. ITEM 1. & 2. BUSINESS AND PROPERTIES GENERAL Mission Resources Corporation is an independent oil and gas exploration and production company headquartered in Houston, Texas. We drill for, acquire, develop and produce natural gas and crude oil primarily, in the Permian Basin (in West Texas and Southeast New Mexico), along the Texas and Louisiana Gulf Coast and in both the state and federal waters of the Gulf of Mexico. At December 31, 2004, our estimated net proved reserves, using constant prices that were in effect at such date, were 93 billion cubic feet ("BCF") of natural gas, 43 billion cubic feet equivalents ("BCFE") of natural gas liquids ("NGLs") and 15 million barrels ("MMBBL") of oil, for total reserves of approximately 2 226 BCFE. Approximately 60% of our estimated net proved reserves were natural gas or NGLs, and approximately 78% were developed at December 31, 2004. OUR BUSINESS STRATEGY AND COMPETITIVE STRENGTHS In July 2004, we announced that we were evaluating strategic alternatives to enhance stockholder value. This process involved: a comprehensive review of the existing asset base and opportunity set; an assessment of the commodities, transactions, debt and equity markets; and an evaluation of our strengths and challenges in the current environment. The conclusions reached when this evaluation was completed in September 2004 were as follows: - Our existing asset base remains under-exploited. - We have a multitude of internal opportunities for value creation. - Potential exists to acquire desirable assets in our core areas. - Debt and equity capital is available to us, if needed, to finance attractive growth opportunities. - Our team is highly qualified and deeply committed to creating stockholder value in a disciplined fashion. Mission's action plan as a result of these conclusions is to: EXPAND THE EXPLORATION PROGRAM IN OUR CORE AREAS -- We have increased our exploration budget to $20 million for 2005, a 132% increase over the $8.6 million spent in 2004. Our exploratory prospects are located primarily in the Gulf Coast onshore area in well-established tertiary producing trends. Through February 2005, we have drilled two successful exploratory wells in Texas: the Weise #1, a Lower Wilcox gas discovery located in Goliad County, and the Iles #1 located in Jefferson County in the Yegua formation. Our first offset well to the Weise #1, the Dehnert #1, also found pay in the Lower Wilcox zone. We are currently drilling three additional offset wells targeting the Lower Wilcox: the Weise #2, the Simmons #1 and the Buckner Foundation #1. One additional location is scheduled to be drilled in the second quarter of 2005. In addition to development wells around our new discoveries, we have scheduled five exploratory prospects for drilling later this year. Three of these are in our Lower Wilcox core area of the central Texas gulf coast, one is an Upper Wilcox stratigraphic/structure play in south Texas and one is a Frio prospect in Brazoria County, Texas. AGGRESSIVELY PURSUE ACQUISITIONS OF PRODUCING PROPERTIES -- We are actively seeking to purchase producing properties with additional upside potential. With the purchase of producing properties, we expect to receive benefits from economies of scale, increased operational control and reduced production volatility as individual wells become a smaller percentage of a larger production base. This strategy will enable us to have more predictable production and reduce our per unit expenses. We are continuing to evaluate transactions that could substantially increase proved reserves. Such acquisitions might be within existing core areas or could create one or more new core areas. Our strategy is for any acquisition to be accretive to cash flow. HEDGE AS APPROPRIATE TO PROTECT OUR INVESTMENTS -- We will continue to hedge at least 50% of our current proved developed production to ensure our cash flow is adequate to service our debt, make our planned capital expenditures and provide an appropriate return on capital. With a significant acquisition, we would consider increasing this percentage to fix returns for the capital we invested. CONTINUE TO DIVEST NON-CORE PROPERTIES FOR GOOD VALUE -- We will continue to optimize our portfolio by divesting non-core properties at favorable prices. Over time, our intent is to divest high operating cost properties or properties that are outside of our core areas. EXPAND BANK FACILITIES AS NEEDED WHILE MAINTAINING DISCIPLINE IN OUR CAPITAL STRUCTURE -- Our previously stated long-term goal is to lower our ratio of debt to total capitalization to below 50%. Although we may borrow funds to finance a specific acquisition, and thus temporarily increase that ratio, we intend to utilize 3 equity to maintain discipline in our capital structure. We currently have a $150 million universal shelf registration in place that increases our ability and flexibility to meet capital needs. As we add reserves through the drill bit or through acquisitions, we expect to expand our bank facilities. MAINTAIN AN OPPORTUNISTIC POSTURE -- We will continue to dedicate the human resources and capital to enable us to move quickly when opportunity arises. OUR OIL AND GAS PROPERTIES RESERVES Our estimated net proved oil and gas reserves at December 31, 2004 were approximately 226 BCFE. In 2004 we more than replaced production through reserve additions and extensions. Also, as part of our strategy to reduce unit costs and increase our percentage of production from natural gas, we acquired the Jalmat field, which added approximately 34.3 BCFE of low operating cost natural gas reserves. Set forth below is a reconciliation of our year-end 2004 reserves, as compared to our year-end 2003 reserves, based upon the evaluation of reserves by Netherland, Sewell & Associates, Inc., our independent reservoir engineering firm. The reserves were calculated using year-end pricing required by the Securities and Exchange Commission ("SEC"):
BCFE ----- Proved reserves at beginning of year........................ 177.9 Revisions of previous estimates............................. 0.1 Extensions and discoveries.................................. 36.1 Production.................................................. (24.1) Sales of reserves in-place.................................. (3.9) Purchase of reserves in-place............................... 40.0 ----- Proved reserves at end of year.............................. 226.1 =====
In general, estimates of economically recoverable oil and natural gas reserves and of the future net cash flows therefrom are based upon a number of factors, such as historical production from the properties, assumptions concerning future oil and natural gas prices, future operating costs and the assumed effects of regulation by governmental agencies, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. Estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary. Mission's actual production, revenues, severance and excise taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. In accordance with applicable requirements of the SEC, the discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless prices or costs subsequent to that date are contractually determined. The estimates include the effects of hedges in place at December 31, 2004. Actual future prices and costs may be materially higher or lower than prices or costs as of the date of the estimate. Actual future net cash flows also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by 4 natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. See "Risk Factors" for a discussion of the uncertainties inherent in preparing reserve estimates. PRODUCTION The following table sets forth our net production and net proved reserves as of and for the year ended December 31, 2004 by geographic area.
NET PRODUCTION ESTIMATED NET PROVED RESERVES ------------------------------ ------------------------------ GAS & GAS GAS & GAS DISCOUNTED OIL NGL EQUIVALENT OIL NGL EQUIVALENT FUTURE NET AREA (MBBLS) (MMCFE) (MMCFE) (MBBLS) (MMCFE) (MMCFE) CASH FLOWS(1) ---- ------- ------- ---------- ------- ------- ---------- ------------- ($000'S) Permian Basin.......... 776 3,965 8,622 11,325 86,986 154,939 $239,547 Gulf Coast............. 581 5,614 9,100 2,843 31,387 48,443 128,570 Gulf of Mexico......... 286 3,850 5,568 801 15,471 20,275 50,354 Other(2)............... 4 785 806 5 2,361 2,394 5,933 ----- ------ ------ ------ ------- ------- -------- 1,647 14,214 24,096 14,974 136,205 226,051 $424,404 ===== ====== ====== ====== ======= ======= ========
--------------- (1) In accordance with SEC requirements, the estimated discounted future net cash flows are based on prices and costs as of the date of the estimate. The average prices on December 31, 2004 for natural gas and oil used in our estimate were $6.18 per MMBTU and $43.33 per BBL, respectively. (2) Includes isolated property interests in Wyoming, Oregon, and Oklahoma. See Note 15 of the Notes to Consolidated Financial Statements for data relating to production volumes, production costs and oil and gas reserve information. The following table provides summary statistics about our most significant properties by geographic area as of December 31, 2004.
PERCENT AVERAGE RESERVE TO GAS/OIL PRODUCTION RATIO IN YEARS(1) ------- ---------------------------- Permian Basin Area Waddell Ranch Field................................ 45/55 19.0 Jalmat Field....................................... 96/4 31.0 TXL North Unit..................................... 34/66 16.2 Goldsmith Field.................................... 25/75 9.2 Wasson Field....................................... 6/94 11.2 Gulf Coast Area South Bayou Boeuf Field............................ 50/50 8.2 Second Bayou Field................................. 46/54 2.5 Reddell Field...................................... 65/35 7.3 Gulf of Mexico Area High Island Block A-553............................ 90/10 4.1 South Marsh Island Block 142....................... 70/30 2.3 Other(2)............................................. 99/1 3.0
--------------- (1) Calculated by dividing total proved reserves for the field by 2004 production for the field. (2) Includes isolated property interests in Wyoming, Oregon and Oklahoma. 5 PERMIAN BASIN AREA Waddell Ranch Field Waddell Ranch field is a large, mature property consisting of 900 producing wells and 300 injection wells. Productive formations range in depth from the Queen formation at 3,000 feet to the Ellenburger formation at 15,000 feet. This property, which covers over 75,000 acres, is located in the Permian Basin in Crane County, Texas. Burlington Resources Inc. is the operator and Mission's interest is approximately 10%. This field has had gross cumulative production of 1.4 trillion cubic feet ("TCF") of natural gas and 422 million barrels of oil. A portion of this field is under waterflood. This field is under continuous development through recompletions, workovers, and new drills. Jalmat Field Mission is the operator and holds an approximate 95% working interest in the Jalmat field, located in the Permian Basin in Lea County, New Mexico. The field consists of 140 producing wells with production primarily from the Yates and 7-Rivers formations at depths ranging from 3,000 to 4,200 feet. Gas production from the Yates and 7-Rivers has a high heating content and is processed at a nearby plant for the extraction of NGL's. Numerous behind pipe recompletions and infill drilling potential exist in both of the Yates and 7-Rivers formations. Additionally, the deeper Queen formation may have waterflood potential. TXL North Unit The TXL North Unit is an active waterflood unit that consists of 260 wells and produces from the Clearfork Tubb formation at a depth of approximately 5,600 feet. Anadarko Petroleum Corporation operates this property, located in the Permian Basin in Ector County, Texas. Mission holds an approximate 20% working interest and 25% net revenue interest. This field is currently on a 10-acre infill program with 48 successful new wells drilled in 2004 with continued drilling expected in 2005. Goldsmith Field The Goldsmith field consists primarily of the CA Goldsmith Unit, operated by XTO Energy Inc., and is located in the Permian Basin in Ector County, Texas. Mission holds a 25% working and net revenue interest in this unit. The field consists of 250 producing wells with production primarily from the Clearfork and Devonian formations at depths ranging from 5,500 to 8,000 feet. Development plans for 2005 include five new drill wells in the Clearfork formation. Wasson Field Mission holds an approximate 37% working interest in the Brahaney Unit in the Wasson field, located in the Permian Basin in Yoakum County, Texas. Apache Corporation operates this waterflood unit that consists of 90 producing wells and produces from the San Andres formation at a depth of approximately 5,200 feet. Production has increased significantly in past few years as a result of a successful infill drilling program. In 2004, seven new wells were drilled and the development drilling program continues with nine wells planned for 2005. GULF COAST AREA South Bayou Boeuf Field South Bayou Boeuf field is located in Lafourche Parish, Louisiana and produces from multiple Miocene-age reservoirs at depths ranging from 10,000 to 12,500 feet. One well was drilled in 2004. Multiple development drilling opportunities exist in other sands in the field. Mission is the operator of the field with an average working interest of 96% in seven producing wells. 6 Second Bayou Field Second Bayou field is located in Cameron Parish, Louisiana. The field produces oil from shallow Miocene-age reservoirs at 5,500 feet and gas from deep Miocene-age reservoirs below 10,000 feet. Mission operates three of the six producing wells and holds an average working interest of 55% in four oil wells and two gas wells. Reddell Field Reddell field is located in Evangeline Parish, Louisiana and produces from the Upper, Middle and Lower Wilcox formations at depths ranging from 10,000 to 13,000 feet. Burlington Resources Inc. is the operator of the field consisting of 16 producing wells. In 2004, four wells were drilled with additional development drilling planned for 2005. Mission holds a 15% working interest in the field. GULF OF MEXICO AREA High Island Block A-553 Mission owns approximately a 37% working interest and is the operator in this property located in federal waters offshore Texas in 260 feet of water. The block contains one platform with seven wells. The seventh well was recently drilled and is being completed. Production is primarily gas with liquid condensate from the Pleistocene and Pliocene formations at depths ranging from 5,000 to 12,000 feet. One additional well is planned for 2005 with more drilling available in future years. South Marsh Island Block 142 This property is located in federal waters offshore Louisiana at a depth of 230 feet. Hunt Petroleum Inc. operates 16 wells on two platforms that produce from the Pleistocene and Pliocene formations at depths ranging from 3,000 to 7,000 feet. Mission owns a 31% working interest. Two successful wells were drilled in 2004 and additional drilling is planned. There are additional development drilling and recompletion opportunities on this block. HISTORICAL DRILLING ACTIVITY Our principal drilling activities during the last three years were focused on properties in the Permian Basin, along the Texas and Louisiana Gulf Coast, South Texas and in the Gulf of Mexico. The following tables set forth the results of drilling activity for the last three years:
EXPLORATORY WELLS ------------------------------------------------------- GROSS NET -------------------------- -------------------------- DRY DRY PRODUCTIVE HOLES TOTAL PRODUCTIVE HOLES TOTAL ---------- ----- ----- ---------- ----- ----- 2002................................. 4 1 5 1.66 0.07 1.73 2003................................. 3 2 5 0.64 0.26 0.90 2004................................. 1 1 2 0.25 0.40 0.65
DEVELOPMENT WELLS ------------------------------------------------------- GROSS NET -------------------------- -------------------------- DRY DRY PRODUCTIVE HOLES TOTAL PRODUCTIVE HOLES TOTAL ---------- ----- ----- ---------- ----- ----- 2002................................ 29 3 32 10.03 1.11 11.14 2003................................ 39 4 43 11.41 1.74 13.15 2004................................ 66 1 67 17.24 0.04 17.28
Six wells were in progress as of December 31, 2004. 7 OUR INTEREST IN PRODUCTIVE WELLS The following table sets forth the number of productive oil and gas wells in which we own interests as of December 31, 2004. Productive wells are defined as producing wells and wells capable of production. Gross wells are the number of wells in which we own a working interest. The number of net wells is the sum of the fractional ownership of working interests that we own directly in gross wells. Therefore, the number of net wells does not represent a number of actual, physical wells, but rather quantifies the actual total working interests we hold in all wells. We compute the number of net wells by adding together the percentage of interests we hold in all our gross wells.
GROSS NET ----- ----- Oil Wells: Permian Basin.......................................... 1,562 282.1 Gulf Coast............................................. 57 41.6 Gulf of Mexico......................................... 36 7.2 Other.................................................. 9 0.2 ----- ----- Total Oil Wells........................................... 1,664 331.1 ----- ----- Gas Wells: Permian Basin.......................................... 114 107.0 Gulf Coast............................................. 59 24.5 Gulf of Mexico......................................... 46 9.1 Other.................................................. 42 6.4 ----- ----- Total Gas Wells........................................... 261 147.0 ----- ----- Total Wells............................................... 1,925 478.1 ===== =====
OUR ACREAGE The following table sets forth information concerning our developed and undeveloped oil and gas acreage as of December 31, 2004. Undeveloped acreage consists of those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. The number of gross acres in the following table refers to the total number of acres in which we own a working interest. The number of net acres is the sum of the fractional ownership of working interests that we own in the gross acres. All of our developed and undeveloped acreage is located in the United States and its territorial waters.
GROSS NET ------- ------- Developed Acreage: Permian Basin.......................................... 114,224 34,148 Gulf Coast............................................. 43,269 14,910 Gulf of Mexico......................................... 166,440 33,986 Other.................................................. 29,739 3,201 ------- ------- Total Developed Acreage................................... 353,672 86,245 ------- ------- Undeveloped Acreage: Permian Basin.......................................... -- -- Gulf Coast............................................. 8,852 3,848 Gulf of Mexico......................................... 42,790 7,413 Other.................................................. 72,819 31,485 ------- ------- Total Undeveloped Acreage................................. 124,461 42,746 ------- ------- Total Acreage............................................. 478,133 128,991 ======= =======
8 The primary terms of our oil and natural gas leases expire at various dates. Some of our undeveloped acreage is "held by production", which means that these leases are active as long as we produce oil or natural gas from the acreage. Upon ceasing production, these leases will expire. OUR PRINCIPAL MARKETS AND CUSTOMERS We sell our natural gas and oil production under fixed or floating market price contracts. Our revenues, profitability, cash flow and future growth depend substantially on prevailing prices for natural gas and oil. Among the factors that can cause this fluctuation are the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions and actual or threatened acts of war, terrorism or hostilities in oil producing regions, the domestic and foreign supply of natural gas and oil, the price of foreign imports and overall economic conditions. Decreases in the prices of natural gas and oil could adversely affect the carrying value of proved reserves, revenues, profitability and cash flow. Although we are not currently experiencing any curtailment of natural gas or oil production, market, economic and regulatory factors may in the future materially affect our ability to sell natural gas or oil production. In 2004 and 2003, sales of oil and natural gas to Shell Trading (US) Company accounted for approximately 26.4% and 21.5% of our oil and gas revenues, respectively. In 2004, sales of oil and natural gas to Conoco Phillips Company accounted for approximately 12.0% of our oil and gas revenues. No other purchaser accounted for more than 10% of our oil and gas revenues in 2004, 2003 or 2002. If we were to lose any one (including Shell Trading (US) Company or Conoco Phillips Company) of our oil and natural gas purchasers, the loss could temporarily delay production and sale of our oil and natural gas in the particular purchaser's service area; however, we believe that we could quickly identify a substitute purchaser. During 2002, several large wholesale purchasers of natural gas experienced significant downgrades in their credit ratings. As a result, many of these companies have either reduced their level of natural gas purchases or have discontinued their purchases of natural gas. Although we do not believe that we have been significantly impacted by these changes, the loss of these large natural gas purchasers could have a detrimental effect on the natural gas market in general and on our ability to find purchasers for our natural gas. When we deem it necessary or prudent we require letters of credit, parent company guarantees or other forms of credit enhancement from our purchasers. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these hedging arrangements also limit the benefits we would realize if prices increase. These financial arrangements take the form of swap contracts or cashless collars and are placed with major trading counter parties we believe represent minimal credit risks. We cannot assure you that these trading counter parties will not become credit risks in the future. For further information concerning our hedging transactions, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk." OUR COMPETITION The oil and natural gas industry is highly competitive. We compete with both independent oil and gas companies and major oil companies in all areas of our operations, including acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have greater financial and technical resources and substantially larger staffs than we do. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling or other activities and has caused significant cost increases. In the fourth quarter of 2004, we began to experience delays in drilling at three of our fields due to delays of contracted drilling rigs and reduced availability for new rigs due to the current increased level 9 of demand throughout our industry. We are unable to predict when, or if, the drilling rig shortages will abate or other such shortages may again occur or how they would affect exploration and exploitation plans. Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We cannot assure you that we will be able to compete successfully for these properties. APPLICABLE LAWS AND REGULATIONS UNITED STATES REGULATIONS Sales and Transportation of Gas Historically, the sale or resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and the regulations promulgated hereunder by the Federal Energy Regulatory Commission ("FERC"). In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining NGA and NGPA price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future. Mission's sales of natural gas are affected by the availability, terms and cost of transportation. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the FERC under the NGA, as well as under section 311 of the NGPA. Since 1985, the FERC has implemented regulations intended to increase competition within the gas industry by making gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. Mission's sale of natural gas is generally made at the market prices at the time of sale. Therefore, even though the Company sells significant volumes to major purchasers, the Company believes other purchasers would be willing to buy the Company's natural gas at comparable market prices. Natural gas continues to supply a significant portion of North America's energy needs and the Company believes the importance of natural gas in meeting this energy need will continue. The tightening of natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue. Sales and Transportation of Oil Sales of oil and condensate can be made at market prices and are not subject at this time to price controls. The price received from the sale of these products will be affected by the cost of transporting the products to market. FERC regulations govern the rates that may be charged by oil pipelines by use of an indexing system for setting transportation rate ceilings. In certain circumstances, rules permit oil pipelines to establish rates using traditional cost of service and other methods of rate making. Legislative Proposals In the past, Congress has been very active in the area of gas regulation. In addition, there are legislative proposals pending in the state legislatures of various states, which, if enacted, could significantly affect the petroleum industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on our operations. Federal, State or Indian Leases To the extent that we conduct operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, 10 and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM") or, in the case our OCS leases in federal waters, Minerals Management Service ("MMS") or other appropriate federal or state agencies. Mission's OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA that are subject to interpretation and change by the MMS. For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds are not currently material, but could become substantial if we expand our areas of operations. There is no assurance that bonds or other surety can be obtained in all cases. We are currently in compliance with the bonding requirements of the MMS. Any such suspension or termination could materially adversely affect Mission's financial condition and results of operations. The Mineral Leasing Act of 1920 (the "Mineral Act") prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies "similar or like privileges" to citizens of the United States. Such restrictions on citizens of a "non-reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and gas leases. It is possible that our common stock will be acquired by citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. STATE REGULATIONS Most states regulate the production and sale of oil and gas, including: - requirements for obtaining drilling permits, - the method of developing new fields, - the spacing and operation of wells - the prevention of waste of oil and gas resources, and - the plugging and abandonment of wells. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both. Mission owns certain natural gas pipeline facilities that we believe meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. 11 ENVIRONMENTAL REGULATIONS General Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Our activities with respect to exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing gas and other products, are subject to stringent environmental regulation by state and federal authorities including the Environmental Protection Agency ("EPA"). Risks are inherent in oil and gas exploration and production operations, and we can give no assurance that significant costs and liabilities will not be incurred in connection with environmental compliance issues. Neither can we predict what effect future regulation or legislation, enforcement policies issued thereunder, and claims for damages to property, employees, other persons and the environment resulting from our operations could have. Solid and Hazardous Waste Mission currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although we utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we currently own or lease or on or under properties that we once owned or leased. In addition, many of these properties are or have been operated by third parties over whom we had no control as to their treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under recent laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination. Mission generates wastes, some of which may be hazardous wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under RCRA and state analogs ("Hazardous Waste"). Furthermore, it is possible that certain wastes generated by our oil and gas operations that are currently exempt from treatment as Hazardous Waste may in the future be designated as Hazardous Waste under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements. Equipment used in the exploration and production of oil and gas may become contaminated with naturally-occurring radioactive material ("NORM") at levels subject to state regulation. Among other things, state regulations require identification of oilfield equipment with NORM levels in excess of specified thresholds, impose worker protection standards, regulate disposal and provide penalties for violations. Mission is subject to such regulatory requirements governing NORM, such regulations may become more stringent and related costs may increase. Superfund The federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on potentially responsible parties ("PRPs") with respect to the release into the environment of substances designated under CERCLA as hazardous substances ("Hazardous Substances"). PRPs include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances released at the site. CERCLA also authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to 12 recover from the PRPs the costs of such action. Although CERCLA generally exempts "petroleum" from the definition of Hazardous Substances, in the course of its operations, Mission has generated and will generate wastes that may be a CERCLA Hazardous Substance. We may also own or operate sites on which Hazardous Substances have been released. Mission may be responsible under CERCLA for all or part of the costs of investigation, remediation, and natural resource damages at sites where Hazardous Substances have been released. We have not been named a PRP under CERCLA nor do we know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. Clean Water Act The Clean Water Act ("CWA") imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined and including wetlands. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into waters of the United States. The CWA and the Oil Pollution Act of 1990 ("OPA") require facilities that store or otherwise handle oil in excess of specified quantities to prepare and implement spill prevention, control and countermeasure plans and facility response plans relating to possible discharges of oil to surface waters. The CWA provides for civil, criminal and administrative penalties for violations, including unauthorized discharges of pollutants and of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other pollutants into state waters. In the event of an unauthorized discharge, Mission may be liable for penalties and costs. Oil Pollution Act The OPA, which amends and augments oil spill provisions of CWA, imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in United States waters and adjoining shorelines. A "responsible party" includes the owner or operator of a facility or vessel that is a source of an oil discharge or poses the substantial threat of discharge, or the lessee or permittee of the area in which a discharging facility covered by OPA is located. OPA assigns joint and several liability, without regard to fault, to each responsible party for oil removal costs and a variety of public and private damages. Few defenses exist to the liability imposed by OPA. In the event of an oil discharge or substantial threat of discharge, Mission may be liable for costs and damages. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in the event of a potential spill. The OPA requires owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10 million in specified state waters and $35 million in federal OCS waters, with higher amounts, up to $150 million based upon worst case oil spill discharge volume calculations. We believe that we currently have established adequate proof of financial responsibility for our offshore facilities. Air Emissions Mission's operations are subject to local, state and federal regulations for the control of emissions of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent requirements including additional permits. Particularly stringent requirements may be imposed on major sources located in non-attainment areas designated as not meeting National Ambient Air Quality Standards established by the EPA. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies may bring lawsuits for civil or criminal penalties or require us to forego construction, modification or operation of certain air emission sources. 13 Coastal Coordination There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act ("CZMA") was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. In Texas, the Texas Legislature enacted the Coastal Coordination Act in 1991 ("CCA"). The CCA provides for the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. The act establishes the Texas Coastal Management Program ("CMP"). The CMP is limited to the nineteen counties that border the Gulf of Mexico and its tidal bays. The act provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. This review may impact agency permitting and review activities and add an additional layer of review to certain activities that we undertake. In Louisiana, state legislation enacted in 1978 established the Louisiana Coastal Zone Management Program ("LCZMP") to protect, develop and, where feasible, restore and enhance coastal resources of the state. Under the LCZMP, coastal use permits are required for certain activities in the coastal zone, even if the activity only partially infringes on the coastal zone. The Coastal Management Division of Louisiana's Department of Natural Resources administers the coastal use permit program which applies in coastal areas of 18 of Louisiana's 64 parishes. Activities requiring such a permit include, among other things, projects involving use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas activities. The LCZMP and its requirement to obtain coastal use permits may result in additional permitting requirements and associated time constraints for our projects. OSHA and other Regulations We are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require Mission to organize and/or disclose information about hazardous materials used or produced in its operations. We believe that we are in substantial compliance with the applicable requirements. In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution. TITLE TO OUR PROPERTIES When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct a preliminary title review of local mineral records. We do conduct title investigations and often obtain a title opinion and curative work is performed with respect to significant defects, if any, before we begin drilling operations. We believe that the methods we use for investigating title prior to acquiring any property are consistent with standards generally accepted in the oil and gas industry and that our practices are adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of accepted practices. 14 Our properties are typically subject, in one degree or another, to one or more of the following: - royalties; - overriding royalties; - a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; - back-ins and reversionary interests; - liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; - pooling, unitization and communitization agreements, declarations and orders; and - easements, restrictions, rights-of-way and other matters that commonly affect oil and gas producing property. To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating net revenue interests and in estimating the size and value of our proved reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for the kind of properties that we own. Up to 85% of our properties are pledged as collateral under our senior secured credit facility. OUR EMPLOYEES At December 31, 2004, Mission had 91 full time employees. In addition to the services of our full time employees, we utilize the services of independent contractors to perform certain services. We believe we have a good relationship with our employees. None of our employees are covered by a collective bargaining agreement. In the beginning of 2003, we were party to a Master Service Agreement ("MSA") dated October 1, 1999, and two service contracts under the terms of which Torch Energy Advisors, Inc. ("Torch") operated our oil and gas properties and marketed our oil and gas production. We terminated the service contracts effective February 1, 2003 and April 1, 2003, respectively. We hired additional qualified employees, including many of the operations staff from Torch, to handle those functions. The MSA was terminated on April 1, 2003 because all service contracts had terminated as of that date. OUR FACILITIES Our corporate office occupies approximately 30,000 square feet of leased office space at 1331 Lamar, Suite 1455, Houston, Texas 77010. We also have leased offices in Giddings, Texas, Lafayette, Louisiana and Eunice, New Mexico from which our employees supervise local oil and gas operations. OUR AVAILABLE INFORMATION Mission's Internet website can be found at www.mrcorp.com. Mission makes available, free of charge, or through the "Investor Relations" section of our Internet website at www.mrcorp.com, access to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed pursuant to Section 13(a) of 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonable practicable after such material is filed or furnished to the Securities and Exchange Commission. 15 RISK FACTORS RISKS RELATED TO FINANCING OUR BUSINESS If we are not able to fund our planned capital expenditures, our cash flow from operations will decrease. We make, and will need to continue to make, substantial capital expenditures for the development, exploration, acquisition and production of oil and gas reserves. Our capital expenditures were $88.1 million, $35.4 million, and $21.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. Historically, we have financed these expenditures primarily with cash flow from operations, the issuance of bonds or bank credit facility borrowings, the issuance of our common stock, or the sale of oil and gas properties. Our current primary sources of liquidity are cash flow from operations, credit facility borrowings, and sales of oil and gas properties. Using estimated prices of $35.00 per BBL and $5.50 per MMBTU, we have budgeted total capital expenditures in 2005 of $71 million, however, we intend to increase or decrease this amount depending upon cash flow generated by operations. Natural gas and oil prices, the timing of our drilling program and drilling results have a significant impact on the cash flows available for capital expenditures and our ability to borrow and raise additional capital. Lower prices and/or lower production may decrease revenues and cash flows, thus reducing the amount of financial resources available to meet our capital requirements. We believe that cash flows from operating activities combined with our ability to control the timing of a significant portion of our future exploration and development requirements will provide us with the flexibility and liquidity to meet our planned capital requirements for 2005. If revenues or our borrowing base decrease for any of the reasons discussed above, we may have limited ability to expend the capital necessary to undertake our 2005 exploration and development program. A reduction in our borrowing base could be the result of lower pricing or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, our lenders' inability to agree to an adequate borrowing base, or adverse changes in our lenders' practices regarding estimation of reserves. We cannot assure you that additional debt or equity financing or cash generated by operations or oil and gas property sales will be available to meet these requirements. We have a highly leveraged capital structure, which limits our financial flexibility. Our capital structure consists of our outstanding 9 7/8% senior notes due 2011 (the "9 7/8% Notes"), our $50.0 million senior secured revolving credit facility and our $25.0 million second lien term loan facility. Although all of our current debt is at lower interest rates than the 10 7/8% senior subordinated notes due 2007 (the "10 7/8% Notes") that were outstanding at December 31, 2003, our capital structure remains highly leveraged, which limits our financial flexibility. Our level of indebtedness has several important effects on our future operations, including: - a substantial portion of our cash flow from operations, approximately $15 million to $17 million in 2005, must be dedicated to the payment of interest on our indebtedness and will not be available for other purposes; - covenants contained in our debt obligations, including those in our senior secured revolving credit facility and $25.0 million term loan facility, require us to meet certain financial tests, and other restrictions, including restrictions with respect to our 9 7/8 Notes, limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in our business, including possible acquisition activities; - our ability to obtain financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be limited; - we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage; - we may be more vulnerable to economic downturns and adverse developments in our industry (especially declines in oil and natural gas prices) or the economy in general; and 16 - our level of indebtedness could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate. Our ability to meet our debt service obligations and to reduce our total indebtedness will be dependent upon future performance, which will be subject to general economic conditions and to financial, business and other factors affecting our operations, many of which are beyond our control. We cannot assure you that our future performance will not be adversely affected by such economic conditions and financial, business and other factors We may incur additional indebtedness, which may intensify the risks described above, including our ability to service our indebtedness. We may incur additional indebtedness. Although the indenture governing our 9 7/8% Notes contains restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially increase. To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations. Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our new senior secured revolving credit facility in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity. Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests. Our senior secured revolving credit facility, our second lien term loan and the indenture governing our 9 7/8% Notes contain a number of significant covenants that, among other things, restrict our ability to: - dispose of assets; - incur or guarantee additional indebtedness and issue certain types of preferred stock; - pay dividends on our capital stock; - create liens on our assets; - enter into sale and leaseback transactions; 17 - enter into specified investments or acquisitions; - repurchase, redeem or retire our capital stock or subordinated debt; - merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries; - engage in specified transactions with affiliates; or - other corporate activities. Also, our senior secured revolving credit facility and our second lien term loan require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our new senior secured revolving credit facility, our new second lien term loan facility and the indenture governing our 9 7/8% Notes impose on us. A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our senior secured revolving credit facility, our second lien term loan and our 9 7/8% Notes. A default, if not cured or waived, could result in acceleration of all of our secured indebtedness and our 9 7/8% Notes. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. Hedging production may limit potential gains from increases in commodity prices or result in losses. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. These financial arrangements take the form of cashless collars or swap contracts and are placed with major trading counter parties we believe represent minimum credit risks. We cannot assure you that these trading counter parties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the other party to the hedging contract defaults on its contract obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may limit the benefit we could receive from increases in the prices for natural gas and oil. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in natural gas and oil prices. RISKS RELATED TO OUR BUSINESS AND INDUSTRY We may be unable to acquire or develop additional reserves. As is generally the case in the oil and natural gas industry, our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number of properties for sale. If we are unable to conduct successful development activities or acquire properties containing proved reserves, our total proved reserves will generally decline as a result of production. Also, our production will generally decline. If our reserves and production decline then the amount we are able to borrow under our senior secured revolving credit facility will also decline. We cannot assure you that we will be able to locate additional reserves, that we will drill economically productive wells or that we will acquire properties containing proved reserves. 18 Market uncertainty and a variety of additional factors beyond our control can create large price fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, which could result in low commodity prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include: - weather conditions in the United States; - the condition of the United States economy; - the actions of the Organization of Petroleum Exporting Countries; - domestic and foreign governmental regulation; - political stability in the Middle East and elsewhere; - the foreign supply of oil and gas; - the price of foreign imports; and - the availability of alternate fuel sources. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the carrying value of our proved reserves, our borrowing capacity, our ability to obtain additional capital, our revenues, profitability and cash flows. Lower prices may also reduce the amount of oil and natural gas that we can produce economically and require us to record full cost ceiling test write-downs. Volatile oil and gas prices make it difficult to estimate the value of producing properties in connection with acquisitions and often cause disruption in the market for oil and gas producing properties as buyers and sellers have difficulty agreeing on transaction values. Price volatility also makes it difficult to budget for and project the return on acquisitions and exploitation, development and exploration projects. To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices or that such hedges will be available on acceptable conditions. We may not be able to market all of or obtain favorable prices for the oil or gas we produce. Our ability to market oil and gas from our wells depends upon numerous domestic and international factors beyond our control, including - the extent of domestic production and imports of oil and gas; - the proximity of gas production to gas pipelines; - the availability of capacity in such pipelines; - the demand for oil and gas by utilities and other end users; - the availability of alternate fuel sources; - the effects of inclement weather; - state, federal and international regulation of oil and gas production; and - federal regulation of gas sold or transported in interstate commerce. We cannot assure you that we will be able to market all of the oil or gas we produce or that we can obtain favorable prices for the oil and gas we produce. 19 You should not place undue reliance on reserve information because reserve information represents estimates. This document contains estimates of our oil and gas reserves and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows attributable to such reserves, including factors beyond our control and the control of reserve engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of - the available data; - assumptions regarding future oil and gas prices and expenditures for future development and exploitation activities; and - engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions based upon production history, development and exploitation activities and prices of oil and gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and estimates in this document. In calculating reserves on a gas equivalent basis, oil was converted to gas equivalent at the ratio of six MCF of gas to one BBL of oil. While this ratio approximates the energy equivalency of gas to oil on a BTU basis, it may not represent the relative prices received by us on the sale of our oil and gas production. You should not assume that the present value of future net revenues referred to in this document and the information incorporated by reference is the current market value of our estimated oil and natural gas reserves. In accordance with Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the Securities and Exchange Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with our operations or the oil and natural gas industry in general will affect the accuracy of the 10% discount factor. Lower oil and natural gas prices may cause us to record ceiling test write-downs. We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% per annum, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. 20 Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we have. The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors may be able to pay more for desirable leases, or evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploration activities and has caused significant price increases. In the event of such shortages, larger competitors may have an advantage in obtaining drilling rigs and equipment. We are unable to predict when, or if, such shortages may again occur or how they would affect our exploration and development program. Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete successfully. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We cannot assure you that we will be successful in acquiring any of these properties. We may have claims asserted against us to plug and abandon wells and restore the surface. In most instances, oil and gas lessees are required to plug and abandon wells that have no further utility and to restore the surface. We are often required to obtain bonds to secure these obligations. In instances where we purchase or sell oil and gas properties, the parties to the transaction routinely include an agreement as to who will be responsible for plugging and abandoning any wells on the property and for restoring the surface. In those cases, we may be required to obtain new bonds or may release old bonds regarding our plugging and abandonment exposure based on the terms of the purchase and sale agreement. However, if a subsequent owner or party to the purchase and sale agreement defaults on its obligations to plug and abandon a well or restore the surface and otherwise fails to obtain a bond to secure the obligation, the landowner or in some cases the applicable state or federal regulatory authority, may assert that we are obligated to plug the well as a prior owner of the property. In other instances, we may receive a demand as a current owner of the property to plug and abandon certain wells in the field and to restore the surface although we are still actively developing the field. Mission has been notified of such claims from certain parties and landowners and from the State of Louisiana. Approximately $181,000, $252,000 and $161,000 in costs were recognized for the abandonment and cleanup of the Bayou Ferblanc field for the years ended December 31, 2004, 2003 and 2002, respectively. Approximately $379,000 in costs were recognized for the proposed settlement of abandonment issues at the West Ponchartrain field in 2003. At this time, it is not possible to determine the amount of potential exposure that we may have for any other claims. Although there can be no assurances, we do not presently believe these claims would have a material adverse effect on our financial condition or operations. In 1993 and 1996 we entered into agreements with surety companies and, at that time, affiliated companies Torch and Nuevo Energy Company ("Nuevo") whereby the surety companies agreed to issue such bonds to Mission, Torch and Nuevo. As part of these agreements, Mission, Torch and Nuevo agreed to be jointly and severally liable to the surety company for any liabilities arising under any bonds issued to Mission, Torch and Nuevo. The amount of bonds presently issued to Nuevo pursuant to these agreements is approximately $34.3 million. Torch currently has no bonds outstanding pursuant to these agreements. We have notified the sureties that we will not be responsible for any new bonds issued to Torch or Nuevo. However, the sureties are permitted under these agreements to seek reimbursement from us, as well as from Torch and Nuevo, if the surety makes any payments under the bonds previously issued to Torch and Nuevo. Effective May 17, 2004, Plains Exploration and Production Company acquired Nuevo Energy Company. 21 Compliance with environmental and other government regulations is costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of material regulations applicable to us, see "Applicable Laws and Regulations -- United States Regulations," "-- State Regulations" and "-- Environmental Regulations." These laws and regulations: - require the acquisition of a permit before drilling commences; - restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; - limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; - require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and - impose substantial liabilities for pollution resulting from our operations. The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs, as well as on the oil and gas industry in general. The Oil Pollution Act of 1990 imposes a variety of regulations on "responsible parties" related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a material adverse impact on us. RISKS RELATING TO OUR ONGOING OPERATIONS The loss of key personnel could adversely affect our ability to operate. Our operations are dependent upon a relatively small group of key management and technical personnel, including, but not limited to, Robert L. Cavnar, our Chairman, Chief Executive Officer and President, Richard W. Piacenti, our Executive Vice President and Chief Financial Officer, John L. Eells, our Senior Vice President -- Exploration and Geoscience, Marshall L. Munsell, our Senior Vice President -- Land and Land Administration and Thomas C. Langford, our Senior Vice President -- General Counsel. We cannot assure you that such individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our operations. The oil and gas business involves many operating risks that can cause substantial losses. Our operations are subject to risks inherent in the oil and gas industry, such as - unexpected drilling conditions, such as blowouts, cratering and explosions; - uncontrollable flows of oil, gas or well fluids; - equipment failures, fires, earthquakes, hurricanes or accidents; and - pollution and other environmental risks. These risks could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Moreover, a portion of our operations are offshore and therefore are subject to a variety of operating risks that occur in the marine environment, such as hurricanes or other adverse weather conditions, and to more extensive governmental regulation, including regulations that may, in certain 22 circumstances, impose strict liability for pollution damage, and to interruption or termination of operations by governmental authorities based on environmental or other considerations. As protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including certain physical damage, employer's liability, comprehensive general liability and worker's compensation insurance. Although we are not insured against all risks in all aspects of our business, such as political risk and risk of major terrorist attacks, we believe that the coverage we maintain, including business interruption insurance on our major revenue producing fields, is customary for companies engaged in similar operations. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our financial position. We cannot control the development of the properties we own but do not operate. As of December 31, 2004, we do not operate wells that represent approximately 55% of our proved reserves. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside our control, including - the timing and amount of capital expenditures; - the operators' expertise and financial resources; - the approval of other participants in drilling wells; and - the selection of suitable technology. If drilling and development activities are not conducted on these properties, we may not be able to increase our production or offset normal production declines. Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations. Our operations could result in a liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, including limited coverage for sudden environmental damages, but do not believe that insurance coverage for all environmental damages that occur over time is available at a reasonable cost. Moreover, we do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or the loss of substantial portions of our properties in the event of certain environmental damages. RISKS RELATED TO OUR COMMON STOCK OUTSTANDING Our stock price is volatile, which could cause you to lose part or all of your investment. The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities of other energy companies, has been and may be highly volatile. Factors such as announcements concerning changes in prices of oil and natural gas, the success of our exploration and development drilling program, the availability of capital, and economic and other external factors, as well as period-to-period fluctuations and financial results, may have a significant effect on the market price of our common stock. 23 Issuance of shares in connection with financing transactions or under stock incentive plans will dilute current stockholders. If we raise additional funds by issuing shares of common stock, or securities convertible into or exchangeable or exercisable for common stock under our effective shelf registration statement or otherwise, or if we enter into additional arrangements to issue common stock in exchange for outstanding debt obligations, further dilution to our existing stockholders will result. New investors could also have rights superior to existing stockholders. Pursuant to our stock incentive plans, our management is authorized to grant stock awards to our employees, directors and consultants. You will incur dilution upon exercise or vesting of any outstanding stock awards. The number of shares of our common stock eligible for future sale could adversely affect the market price of our stock. The issuance of a significant number of shares of common stock upon the exercise of stock options, or the availability for sale or sale of a substantial number of the shares of common stock eligible for future sale under effective registration statements, Rule 144 or otherwise, could adversely affect the market price of the common stock. We have reserved approximately 7.2 million shares of common stock for issuance under outstanding options, all of which are registered for resale on currently effective registration statements. In addition, we have registered the resale of 16.75 million shares of common stock that were issued in exchange for $40 million of our 10 7/8% Notes, and 312,000 shares of common stock issued in connection with the offering of our 9 7/8% Notes. We have not and do not expect in the near future to pay dividends. We have never declared or paid any cash dividends on our common stock and have no intention to do so in the near future. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indentures executed in connection with our 9 7/8% Notes. In addition, our senior secured revolving credit facility and our second lien term loan contain provisions that may have the effect of limiting or prohibiting the payment of dividends. Our certificate of incorporation, bylaws, rights plan and Delaware law have provisions that discourage corporate takeovers and could prevent stockholders from realizing a premium on their investment. Certain provisions of our certificate of incorporation, bylaws and rights plan and the provisions of the Delaware General Corporation Law may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the board may determine. Additional provisions include restrictions on business combinations and on stockholder action by written consent. We are also subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with an interested stockholder for a period of three years following the date on which the stockholder became an interested stockholder. These provisions, alone or in combination with each other and with the rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. In September 1997, our board of directors adopted a rights plan, pursuant to which uncertificated stock purchase rights were distributed to our stockholders at a rate of one right for each share of common stock held of record as of September 26, 1997. The rights plan is designed to enhance the board's ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect stockholders against attempts to acquire us by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover not supported by our board, including a 24 takeover that may be desired by a majority of our stockholders or involving a premium over the prevailing stock price. ITEM 3. LEGAL PROCEEDINGS Mission is involved in litigation relating to claims arising out of its operations in the normal course of business, including workmen's compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on Mission's business or financial position. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Mission's common stock is traded on The Nasdaq National Market (Symbol: MSSN). The following table sets forth the range of the high and low sales prices, as reported by Nasdaq for our common stock for the periods indicated.
SALES PRICE ------------- QUARTER ENDED: HIGH LOW -------------- ----- ----- March 31, 2003.............................................. $0.47 $0.22 June 30, 2003............................................... $1.88 $0.25 September 30, 2003.......................................... $2.45 $1.30 December 31, 2003........................................... $2.99 $1.62 March 31, 2004.............................................. $3.25 $2.17 June 30, 2004............................................... $6.11 $3.12 September 30, 2004.......................................... $6.53 $4.61 December 31, 2004........................................... $6.80 $5.24
We have not paid dividends on our common stock and do not anticipate paying cash dividends in the immediate future as we contemplate that our cash flows will be used for continued growth of our operations. In addition, certain covenants contained in our financing arrangements restrict the payment of dividends (see Management's Discussion and Analysis of Financial Condition and Results of Operations -- Financial Condition -- Financing and Note 8 of the Notes to Consolidated Financial Statements). There were approximately 1,051 stockholders of record as of February 28, 2005. 25 ITEM 6. SELECTED FINANCIAL DATA The following selected financial data with respect to Mission should be read in conjunction with the Consolidated Financial Statements and supplementary information included in Item 8 (amounts in thousands, except per share data).
YEAR ENDED DECEMBER 31, ---------------------------------------------------- 2004 2003 2002 2001 2000 -------- -------- -------- -------- -------- Gas revenues................................ $ 79,050 $ 46,443 $ 42,953 $ 60,924 $ 66,953 Oil revenues................................ 49,657 52,914 69,926 72,311 45,300 Gas plant revenues.......................... -- -- -- 4,456 6,070 Gain (loss) on extinguishment of debt....... (2,606) 23,476 -- -- -- Interest and other income (loss)............ (461) 1,141 (7,415) 4,386 957 -------- -------- -------- -------- -------- Total revenues............................ 125,640 123,974 105,464 142,077 119,280 Lease operating expense..................... 29,060 32,728 43,222 44,773 24,553 Taxes other than income..................... 9,400 8,251 9,246 6,656 6,273 Transportation costs........................ 346 349 834 73 270 Gas plant expenses.......................... -- -- -- 2,118 2,677 Asset retirement obligation accretion expense................................... 1,202 1,263 -- -- -- Depreciation, depletion and Amortization.... 44,229 38,501 43,291 45,106 32,654 Impairment expense.......................... -- -- 16,679 27,971 -- Disposition of hedges....................... -- -- -- -- 8,671 Uncollectible gas revenues.................. -- -- -- 2,189 -- Loss on sale of assets...................... -- -- 2,645 11,600 -- General and administrative Expenses......... 16,871 10,856 12,758 15,160 8,821 Interest and related expenses............... 19,818 25,565 26,853 23,664 15,375 Provision for income tax (benefit).......... 1,765 2,358 (11,580) (9,055) (12,222) -------- -------- -------- -------- -------- Total expenses.............................. 122,691 119,871 143,948 170,255 87,072 Cumulative effect of a change in accounting method, net of deferred taxes............. -- 1,736 -- 2,767 -- -------- -------- -------- -------- -------- Net income (loss)........................... $ 2,949 $ 2,367 $(38,484) $(30,945) $ 32,208 ======== ======== ======== ======== ======== Earnings (loss) per common share............ $ 0.08 $ 0.10 $ (1.63) $ (1.54) $ 2.32 Earnings (loss) per common share-diluted.... $ 0.07 $ 0.10 $ (1.63) $ (1.54) $ 2.27 Working capital............................. $(10,261) $ 16,277 $ 952 $ 105 $ 7,212 Long-term debt, net of current Maturities... $170,000 $198,496 $226,431 $261,695 $125,450 Stockholders' equity........................ $112,005 $ 74,940 $ 65,377 $110,240 $ 56,960 Total assets................................ $377,903 $357,326 $342,404 $447,764 $221,545
26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Mission is an independent oil and gas exploration and production company. We drill for, acquire, develop and produce natural gas and crude oil. Our property portfolio is comprised of long-lived, low-risk assets, like those in the Permian Basin, and multi-reservoir, high-productivity assets found along the Gulf Coast and in the Gulf of Mexico. Our operational focus remains on efficient, well managed upstream natural gas and crude oil exploration and production. We will continue to pursue complementary acquisitions when the appropriate opportunities present themselves. Mission's results of operations for the year 2004 included the following financial and operational highlights. - Acquired approximately 34.3 BCFE at the Jalmat field, located in the Permian Basin in New Mexico. - Redeemed our 10 7/8% Notes and issued $130.0 million of new 9 7/8% Notes. - Established a new senior secured revolving credit facility, making available $30.0 million for short-term borrowings and an additional $20.0 million for acquisitions. - Entered into a new $25.0 million second lien term loan. - Reduced long-term debt by $28.5 million and interest expense by $6 million for the year ended December 31, 2004 as compared to the same period in 2003. - Reduced operating expenses per MCFE 15.4% from $1.43 for the year ended December 31, 2003 to $1.21 for the year ended December 31, 2004. - Drilled 66 successful developmental wells and one successful exploratory well that increased reserves enough to fully replace 2004 production. - Completed building our exploration team of experienced geophysicists and geologists with significant expertise in the industry and our core areas. - Hedged over 50% of 2005 proved developed producing reserves at a weighted average floor price of $31.21 per BBL and $5.02 per MMBTU, with additional hedges on 2006 production. - Doubled ownership interest in the Chocolate Bayou, Southwest Lake Boeuf, Backridge and West Lake Verret fields by acquiring approximately 6 BCFE of reserves. RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2004 COMPARED TO YEAR ENDED DECEMBER 31, 2003 Net Income/Loss -- Net income for the year ended December 31, 2004 was $2.9 million, or $0.07 per share on a diluted basis, while the net income for the year ended December 31, 2003 was $2.4 million, or $0.10 per share on a diluted basis. In 2003, our purchase and retirement of $107.6 million principal amount of our 10 7/8% Notes generated a $23.5 million gain, $15.3 million net of tax, on the extinguishment of debt. In 2004, our repurchase and retirement of the remaining $117.4 million principal amount of our 10 7/8% Notes, along with other debt refinancing costs, generated a net loss of $2.6 million, $1.7 million net of taxes. Absent the debt extinguishment gains and (losses), net income (loss) for the years ended December 31, 2004 and 2003, would have been $4.6 million and ($12.9) million, respectively. See "Financial Condition-Financing" section below for additional information about the debt retirement transactions. The $17.5 million improvement, net of debt extinguishment, in the twelve month period ended December 31, 2004 resulted from increased gas production, higher oil and gas prices and lower interest and lease operating expenses. This was partially offset by a $4.1 million non-cash increase in G&A expense ($2.6 million, net of taxes) from the issuance, to our Chairman and CEO, of stock options to replace stock appreciation rights. 27 Oil and Gas Revenues -- Oil and gas revenues were $128.7 million in the year ended December 31, 2004, compared to $99.3 million for the respective period in 2003. The table below details the components of oil and gas revenues and their respective changes between the periods (dollar amounts in millions, except prices):
YEAR ENDED DECEMBER 31, CHANGE ----------------- ----------------- 2004 2003 DOLLARS PERCENT ------- ------- ------- ------- Oil revenue...................................... $ 65.7 $ 62.3 $ 3.4 5.5% Oil hedge settlements............................ (16.0) (9.4) (6.6) (70.2)% ------- ------- Net oil revenue.................................. 49.7 52.9 Gas revenue...................................... 83.6 52.8 30.8 58.3% Gas hedge settlements............................ (4.6) (6.4) 1.8 28.1% ------- ------- Net gas revenue.................................. $ 79.0 $ 46.4 Oil production (MBBLS)........................... 1,647 2,098 (451) (21.5)% Gas production (MMCF)............................ 14,214 10,314 3,900 37.8% Gas equivalent (MMCFE)........................... 24,096 22,902 1,194 5.2% Average sales prices, excluding hedges Oil ($ per Bbl)................................ $ 39.88 $ 29.69 $10.19 34.3% Natural Gas ($ per MCF)........................ $ 5.89 $ 5.12 $ 0.77 15.0% Average sales prices, including hedges Oil ($ per Bbl)................................ $ 30.15 $ 25.22 $ 4.93 19.5% Natural Gas ($ per MCF)........................ $ 5.56 $ 4.50 $ 1.06 23.6%
The sale of the East Texas and Raccoon Bend fields in the last half and fourth quarter of 2003, respectively, are the primary causes for the 21.5% decline in oil production. Gas production, however, increased 37.8%, more than offsetting the oil production decline and resulted in a combined MMCFE increase of 5.2%. The primary reasons for the gas increase are the January and April 2004 acquisitions of the Jalmat field in Lea County, New Mexico. The Jalmat acquisition, along with production increases from the LeBlanc #1 well in Vermilion Parish, Louisiana, the South Marsh Island A-11 and C-5 wells, offshore Louisiana, and the High Island 553 A-7 recompletion, offshore Texas, account for most of the production increase. Increased pre-hedge oil and gas prices averaged $39.88 per Bbl and $5.89 per MCF or 34.3% and 15.0% higher, respectively, in the twelve month period ended December 31, 2004 compared to $29.69 per Bbl and $5.12 per MCF in the same period of 2003. Realized oil and gas prices, including the effect of hedges, were $4.93 per Bbl and $1.06 per MCF higher, respectively, for the year ended December 31, 2004, as compared to the same period in 2003. Several factors, including instability in the Middle East, lower inventories and a cold winter contributed to the commodity price increases. 28 Costs of Oil and Gas Production -- In addition to analyzing gross changes in costs, management finds it useful to look at certain costs on a per unit basis. The table below details our costs of oil and gas production by cost type both in dollars incurred and, where useful, in dollars per MCFE, and their respective changes between the periods (dollars in millions, except per unit amounts).
YEAR ENDED DECEMBER 31, CHANGE ------------- ----------------- 2004 2003 DOLLARS PERCENT ----- ----- ------- ------- Lease operating expense.............................. $29.1 $32.7 $ (3.6) (11.0)% Lease operating expense per MCFE..................... 1.21 1.43 (0.22) (15.4)% Taxes other than income:(1) Production taxes................................... 6.9 5.2 1.7 32.7% Property taxes..................................... 2.1 2.6 (0.5) (19.2)% Other taxes........................................ 0.4 0.5 (0.1) (20.0)% ----- ----- ------ ----- Total taxes other than income:.................. 9.4 8.3 1.1 13.3% ----- ----- ------ ----- Transportation costs(1).............................. 0.3 0.3 -- -- Depreciation, depletion and amortization............. 44.2 38.5 5.7 14.8% Depreciation, depletion and amortization per MCFE.... $1.80 $1.65 $ 0.15 9.1%
--------------- (1) Taxes other than income and transportation costs relate to specific fields or production, therefore analysis of such costs per unit of total production is not useful. Total lease operating expenses for the year 2004 decreased 11% from 2003 levels, and decreased 15.4% on a per MCFE basis. Production increases along with lease operating expense decreases contributed to the per MCFE cost decrease. In gross dollars, the most significant cost reductions related to the sale of high cost properties and subsequent redeployment of proceeds into lower cost gas properties. The cost per MCFE of the East Cameron and East Texas fields sold in August 2003, and the Raccoon Bend oil field sold in the fourth quarter of 2003, were significantly higher than the cost per MCFE of the Jalmat field, which was purchased in the first quarter of 2004. In the second quarter of 2004, we recovered approximately $575,000 of previously paid Waddell Ranch field lease operating expenses as a result of in-house review of billable costs. Exclusive of this recovery, recurring lease operating expense on an MCFE basis was $1.23 for the twelve months ending December 31, 2004 as compared to $1.43 for the twelve months ending December 31, 2003. In the fourth quarter of 2004, our lease operating expense increased for two reasons. First, workovers are being performed due to near-record high commodity prices that probably would not have been performed in the past, and second, the cost of basic oil field services has increased. We expect these trends to continue into 2005. Production taxes, depending upon the jurisdiction, are calculated using a percentage of revenue or a per-unit of production rate. In general, production taxes increase as revenue and production increase. In 2004, the 32.7% increase in production taxes was disporportionately larger than our revenue increase because Louisiana's tax rate on natural gas increased by 40%. Property taxes are assessed based upon property value calculated at the beginning of each year. Our reduced number of properties coupled with reductions in the assessed values of our remaining properties resulted in the property tax reduction in 2004. Assessed values are based upon beginning of the year reserves and the previous year's average realized price. As a result of the sale of Texas properties late in 2003, and their replacement with properties in New Mexico, a state with lower property taxes than Texas, our property taxes have been reduced by 19.2%. Depreciation, depletion and amortization ("DD&A") is 14.8% higher for the twelve months ended December 31, 2004 over the same period in 2003. This increase is due to a 9.1% higher DD&A rate and a 5.2% increase in production on an MCFE basis, discussed under Oil and Gas Revenues above. The DD&A rate is calculated by dividing the net property costs plus future development costs, by the remaining BOE 29 of reserves. The $0.15 increase in DD&A on a per MCFE basis reflects the impact of a $40.0 million increase in future development costs. The effect of this increase to the depletable base was mitigated by an increase in reserves as a result of the Jalmat acquisition in January and April 2004 and reserve additions described in our December 31, 2004 reserve report prepared by Netherland, Sewell and Associates, Inc. Asset Retirement Obligation Accretion Expense -- The liability recorded for our asset retirement obligation represents the estimate of such costs as of the end of the reporting period. Each quarter, we are required to increase the liability to account for the passage of time, resulting in this accretion expense. Income Taxes -- Federal and state income taxes for the year ended December 31, 2004 were based upon a 37.4% effective tax rate which represented a change from the 36.5% effective tax rate of 2003. The effective rate is calculated by dividing income tax provision by net income before taxes. There was a $3.9 million valuation allowance on deferred taxes applicable at December 31, 2004. In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are available. Based upon the currently available evidence, management believes it is more likely than not that a) the Company will not realize the deferred tax benefit associated with its interest in the Carpatsky production payment and b) a portion of the Company's state income tax loss carryforwards will not be utilized. Interest and Other Income -- Interest and other income decreased $1.6 million from a net gain of $1.1 million reported for the year 2003 to a net loss of $461,000 reported for the year 2004. Gains or losses related to hedge ineffectiveness, as computed under the requirements of SFAS. No. 133, are the most significant portion of this line item. A $1.0 million net gain from hedge ineffectiveness was recorded in 2003 while a net gain of $0.1 million was recorded in 2004. Other factors contributing to the decrease in interest and other income; include, $361,000 of equity in the earnings of White Shoal Pipeline Corporation in 2003 compared to $53,000 in 2004 and bad debt recoveries of $109,000 in 2003 compared to bad debt expense of $441,000, in 2004. Interest and Related Expenses -- Interest expense decreased 22.7% to $19.8 million for the year ended December 31, 2004 from $25.6 million for the year ended December 31, 2003. The following table details the components of interest and their respective changes between the periods (dollar amounts in millions).
YEAR ENDED DECEMBER 31, CHANGE ------------- ----------------- 2004 2003 DOLLARS PERCENT ----- ----- ------- ------- Interest rate swap gain.............................. $ -- $(0.5) $ 0.5 N/A Interest on 10 7/8% Notes, net of amortized premium............................................ 3.9 16.2 (12.3) (75.9)% Interest on 9 7/8% Notes............................. 9.4 -- 9.4 N/A Amortization of financing costs...................... 1.7 2.5 (0.8) (32.0)% Interest on term loan................................ 4.2 7.3 (3.1) (42.5)% Interest on credit facility.......................... 0.6 0.1 0.5 500.0% ----- ----- ------ Reported interest and related expense.............. $19.8 $25.6 $ (5.8) (22.7)% ===== ===== ======
The interest rate swap was cancelled in February 2003 and was not replaced. Throughout 2003 and in early 2004, we repurchased approximately $137.6 million in 10 7/8% Notes. On May 10, 2004, the remaining $87.4 million of 10 7/8% Notes were redeemed. The redemption of all the 10 7/8% Notes and subsequent issuance of the 9 7/8% Notes resulted in a significant reduction in interest paid for the year ended December 31, 2004 as compared to the same period in 2003. Also, throughout 2003 and early 2004 interest expense on the term loan was based on an $80 million principal balance at 12% interest. On April 8, 2004, as part of the debt refinancing, the principal balance on the term loan was repaid and replaced with a senior secured revolving credit facility and a second lien term loan with a combined balance of $40 million and interest rates between 3.1% and 7.6%. This decrease in balance and interest 30 rates resulted in a reduction in interest paid for the year ended December 31, 2004, as compared to the same period in 2003. General and Administrative Expenses -- General and administrative expenses totaled approximately $16.9 million in the year ended December 31, 2004 and $10.9 million in the year ended December 31, 2003. This increase is primarily the result of the recognition of a non-cash compensation expense of $4.1 million from the issuance of stock options to replace stock appreciation rights. The options were granted with a strike price of $0.55 per share, which is the same exercise price as the surrendered stock appreciation rights. As a result of these options having an exercise price below the market value for Mission's common stock, we were required to recognize this non-cash expense. An increase in separation costs of $0.4 million along with additional costs relating to Sarbanes-Oxley Act compliance of approximately $0.5 million also accounted for a portion of the increase. A general increase in staffing during the twelve month period ended December 31, 2004 has contributed to higher salaries and benefits than that of the same period in 2003. Some costs incurred in 2004 are not expected to be recurring. The non-cash compensation expense and separation costs are considered one-time events. While many of these costs are not expected to reoccur in 2005, our total general and administrative expenses are anticipated to remain near 2004 levels as headcount in 2005 goes up. Salaries and benefits will increase and public company expenses will continue to rise as the Company increases in size. YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002 Net Income/Loss -- Net income for the year ended December 31, 2003 was $2.4 million, or $0.10 per share on a diluted basis, while the net loss for the year ended December 31, 2002 was $38.5 million, or $1.63 per share on a diluted basis. In 2003, our purchase and retirement of $107.6 million principal amount of our 10 7/8 Notes generated a $23.5 million gain, $15.3 million net of tax, on the extinguishment of debt. See "Financial Condition -- Financing" section below for additional information about the debt retirement transactions. In 2002, we recognized a $16.7 million goodwill impairment. Absent the debt extinguishment in 2003 and goodwill impairment in 2002, net loss for these years would have been $12.9 million and $21.8 million, respectively. 31 Oil and Gas Revenues -- Oil and gas revenues were $99.3 million in the year ended December 31, 2003, compared to $112.9 million for the respective period in 2002. The table below details the components of oil and gas revenues and their respective changes between the periods (dollar amounts in millions, except prices):
YEAR ENDED DECEMBER 31, CHANGE ----------------- ------------------ 2003 2002 DOLLARS PERCENT ------- ------- -------- ------- Oil revenue.................................... $ 62.3 $ 71.5 $ (9.2) (12.9%) Oil hedge settlements.......................... (9.4) (1.6) (7.8) (487%) ------- ------- Net oil revenue................................ 52.9 69.9 Gas revenue.................................... 52.8 41.7 11.1 26.6% Gas hedge settlements.......................... (6.4) 1.3 (7.7) (592%) ------- ------- Net gas revenue................................ $ 46.4 $ 43.0 Oil production (MBBLS)......................... 2,098 3,157 (1,059) (33.5%) Gas production (MMCF).......................... 10,314 14,120 (3,806) (27.0%) Gas equivalent (MMCFE)......................... 22,902 33,062 (10,160) (30.7%) Average sales prices, excluding hedges Oil ($ per Bbl).............................. $ 29.69 $ 22.66 $ 7.03 31.0% Natural Gas ($ per MCF)...................... $ 5.12 $ 2.95 $ 2.17 73.6% Average sales prices, including hedges Oil ($ per Bbl).............................. $ 25.22 $ 22.15 $ 3.07 13.9% Natural Gas ($ per MCF)...................... $ 4.50 $ 3.04 $ 1.46 48.0%
The property sales in late 2002 plus the additional sales in the fourth quarter of 2003 are the primary cause of the oil and gas production declines. Gas production increases from drilling, recompletions and workovers completed at South Marsh Island, North Leroy and West Lake Verret partially offset the production declines. Because these projects were completed late in 2003, their impact in 2003 was small, but continued production from these projects benefited our 2004 results. In addition, the favorable impact of high commodity prices offset most of the production decreases. Several factors, including instability in the Middle East and a cold winter, contributed to the commodity price increases. Costs of Oil and Gas Production -- In addition to analyzing gross changes in costs, management finds it useful to look at certain costs on a per unit basis. The table below details our costs of oil and gas production by cost type both in dollars incurred and, where useful, in dollars per MCFE, and their respective changes between the periods (dollars in millions, except per unit amounts).
YEAR ENDED DECEMBER 31, CHANGE ------------- ----------------- 2003 2002 DOLLARS PERCENT ----- ----- ------- ------- Lease operating expense.............................. $32.7 $43.2 $(10.5) (24.3%) Lease operating expense per MCFE..................... 1.43 1.31 0.12 9.2% Taxes other than income(1)........................... 8.3 9.2 (0.9) (9.8%) Production taxes................................... 5.2 5.0 0.2 4.0% Property taxes..................................... 2.6 3.8 (1.2) (31.6%) Other taxes........................................ 0.5 0.4 0.1 25.0% Transportation costs(1).............................. 0.3 0.8 (0.5) (62.5%) Depreciation, depletion and amortization............. 38.5 43.3 (4.8) (11.1%) Depreciation, depletion and amortization per MCFE.... $1.65 $1.29 $ 0.36 27.9%
--------------- (1) Taxes other than income and transportation costs relate to specific fields or production, therefore analysis of such costs per unit of total production is not useful. 32 Total lease operating expenses for the year 2003 decreased 24.3% from 2002 levels, but increased 9.2% on a per MCFE basis. Production declines contributed to the per MCFE cost increase. In gross dollars, the most significant cost reductions related to the sale of properties at auction in November 2002, the sale of the Pt. Pedernales field in March 2003, the sale of the East Texas and East Cameron fields in August 2003 and the sale of the Raccoon Bend field in the fourth quarter of 2003. The East Texas and Raccoon Bend fields consisted of high per MCFE cost oil properties. Production taxes, depending upon the jurisdiction, are calculated using a percentage of revenue or a per-unit of production rate. They vary with both price and production levels. Property taxes are assessed based upon property value calculated at the beginning of each year. Our reduced number of properties coupled with reductions in the assessed values of our remaining properties resulted in the property tax reduction in 2003. Assessed values are based upon beginning of the year reserves and the previous year's average realized price. Because our depreciation, depletion and amortization ("DD&A") is calculated on the units of production method, the production decrease resulting from normal production declines and from property sales is resulting in the overall decline in DD&A expense. The increase in DD&A on a per MCFE basis reflected the impact of decreases in reserves due to property sales. Asset Retirement Obligation Accretion Expense -- Asset retirement obligation accretion expense was a new category of expense for 2003 that resulted from the implementation of SFAS No. 143. The liability recorded for our asset retirement obligation represented the estimate of such costs as of the end of the reporting period. Each quarter, we are required to increase the liability to account for the passage of time, resulting in this accretion expense. Income Taxes -- Federal and state income taxes for the year ended December 31, 2003 were based upon a 36.5% effective tax rate which represented a change from the 23.1% effective tax rate of 2002. The 2002 effective rate, as calculated by dividing income tax benefit by net loss before taxes, was lower primarily because the impairment of goodwill is not an allowable tax deduction. In December 2003, we became subject to tax limitations imposed under Section 382 of the Internal Revenue Code ("382 Limitations"). These limitations could impact the potential future realization of our tax net operating losses and other deferred tax assets. Based upon estimates of our recoverable reserves, future production and related taxable income, management has determined that the 382 Limitations have not currently resulted in our deferred assets being impaired. Interest and Other Income -- Interest and other income increased $8.6 million from a net loss of $7.4 million reported for the year 2002 to a net gain of $1.1 million reported for the year 2003. Gains or losses related to hedge ineffectiveness, as computed under the requirements of SFAS. No. 133, were the most significant portion of this line item. A $9.0 million net loss from hedge ineffectiveness was recorded in 2002 while a net gain of $1.0 million was recorded in 2003. A $1.7 million gain from the settlement of a royalty calculation dispute with the MMS was also recorded in 2002. 33 Interest and Related Expenses -- Interest expense decreased 4.8% to $25.6 million for the year ended December 31, 2003 from $26.9 million for the year ended December 31, 2002. The following table details the components of interest and their respective changes between the periods (dollar amounts in millions).
YEAR ENDED DECEMBER 31, CHANGE ------------- ----------------- 2003 2002 DOLLARS PERCENT ----- ----- ------- ------- Interest rate swap (gain) loss....................... $(0.5) $(2.2) $ 1.7 77.3% Interest on 10 7/8% Notes, net of amortized premium............................................ 16.2 24.2 (8.0) (33.1)% Amortization of financing costs...................... 2.5 3.1 (0.6) (19.4)% Interest on term loan................................ 7.3 -- 7.3 N/A Interest on credit facility.......................... 0.1 1.8 (1.7) (94.4)% ----- ----- ----- Reported interest and related expense.............. $25.6 $26.9 $(1.3) (4.8)% ===== ===== =====
The interest rate swap was cancelled in February 2003, limiting our exposure to interest rate volatility and resulting in a $520,000 gain recognized in the first quarter of 2003. The March 2003 repurchase of $97.6 million of our 10 7/8% Notes and their replacement with an $80.0 million term loan facility bearing interest at 12% generated interest savings of approximately $95,000 per month beginning in the second quarter of 2003. General and Administrative Expenses -- General and administrative expenses totaled approximately $10.9 million in the year ended December 31, 2003 and $12.8 million in the year ended December 31, 2002. In 2002, employees of Torch performed most of our accounting, operating and marketing functions, and we paid Torch a management fee for these outsourced services. By the end of April 2003 we had terminated all outsourcing contracts with Torch, decreasing our management fee costs; however, employee costs increased as a result of our increased staffing to replace Torch employees combined with severance costs related to the reorganization partially offsetting the management fee savings. Certain costs incurred in 2003 were not expected to be recurring. Our legal costs were higher as a result of several settled lawsuits and the implementation of the new corporate governance requirements. We also performed an extensive review of our lease and well records in connection with the implementation of a new land system. FINANCIAL CONDITION CAPITAL STRUCTURE In 2004 we reduced our indebtedness by $28.5 million lowering our interest expense in 2005 to approximately $15 to $17 million. This was accomplished by taking the following steps in the first half of 2004: - The issuance of 16.75 million shares of common stock in exchange for $40 million of the 10 7/8% Notes in three transactions in December 2003, February 2004 and March 2004. - The issuance of $130 million of the 9 7/8% Notes, and the simultaneous establishment of a new senior secured revolving credit facility and a new second lien term loan. - The redemption of the remaining $87.4 million aggregate principal amount of the 10 7/8% Notes at a premium using a portion of the proceeds from the issuance of the 9 7/8% Notes. - The repayment in full of the prior term loan facility using the remaining portion of the proceeds from the issuance of the 9 7/8% Notes, together with $21.5 million that was advanced under the new senior secured revolving credit facility and $25 million that was borrowed under the new second lien term loan. Interest expense remains a significant use of cash that reduces the cash available for the exploration and development of oil and gas properties. 34 FINANCING Our outstanding indebtedness totaled $170 million at December 31, 2004. The nature of our indebtedness as of December 31, 2004 and December 31, 2003 is summarized on the table below (amounts in thousands).
DECEMBER 31, DECEMBER 31, 2004 2003 --------------- --------------- Term loan facility.......................................... $ -- $ 80,000 10 7/8% Notes............................................... -- 117,426 Unamortized premium on 10 7/8% Notes........................ -- 1,070 Second lien term loan facility.............................. 25,000 -- Senior secured revolving credit facility(1)................. 15,000 -- 9 7/8% Notes................................................ 130,000 -- -------- -------- Total debt.................................................. $170,000 $198,496 ======== ========
--------------- (1) Amounts available for borrowing at December 31, 2004 and 2003 under the revolving credit facilities were $34.9 million and $12.5 million, respectively. On April 8, 2004, we issued senior notes, announced the redemption of our 10 7/8% Notes and replaced both our revolving credit facility and term loan. Those transactions and the details of the resulting debt are discussed below. 9 7/8% Notes On April 8, 2004, we issued $130.0 million of our 9 7/8% Notes which are guaranteed on an unsubordinated, unsecured basis by all of our current subsidiaries. Interest on the notes is payable semi-annually, on each April 1 and October 1, commencing on October 1, 2004. A portion of the net proceeds from the offering of the 9 7/8% Notes was set aside to redeem, on May 10, 2004, the $87.4 million aggregate principal amount of the 10 7/8% Notes that remained outstanding. On April 8, 2004, the remainder of the net proceeds from the offering of the 9 7/8% Notes, together with $21.5 million that was advanced under the new senior secured revolving credit facility (as described below) and $25.0 million that was borrowed under the new second lien term loan (as described below), was used to completely discharge all of our outstanding indebtedness under our prior revolving credit facility and term loan. At any time on or after April 9, 2005 and prior to April 9, 2008, we may redeem up to 35% of the aggregate original principal amount of the 9 7/8% Notes, using the net proceeds of equity offerings, at a redemption price equal to 109.875% of the principal amount of the 9 7/8% Notes, plus accrued and unpaid interest. On or after April 9, 2008, we may redeem all or a portion of the 9 7/8% Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest, if redeemed during the twelve-month period beginning on April 9 of the years indicated below:
YEAR PERCENTAGE ---- ---------- 2008........................................................ 104.93750% 2009........................................................ 102.46875% 2010........................................................ 100.00000%
If we experience specific kinds of change of control, we may be required to purchase all or part of the 9 7/8% Notes at a price equal to 101% of the principal amount together with accrued and unpaid interest. 35 The 9 7/8% Notes contain covenants that, subject to certain exceptions and qualifications, limit our ability and the ability of certain of our subsidiaries to: - incur additional indebtedness or issue certain types of preferred stock or redeemable stock; transfer or sell assets; - enter into sale and leaseback transactions; - pay dividends or make other distributions on stock, redeem stock or redeem subordinated debt; - enter into transactions with affiliates; - create liens on our assets; - guarantee other indebtedness; - enter into agreements that restrict dividends from subsidiaries; - make investments; - sell capital stock of subsidiaries; and - merge or consolidate. Standard and Poor's and Moody's currently publish debt ratings for the 9 7/8% Notes. Their ratings consider a number of items including our debt levels, planned asset sales, near-term and long-term production growth opportunities, capital allocation challenges and commodity price levels. Standard & Poor's rating on the 9 7/8% Notes is "CCC" and Moody's rating is "Caa2." A decline in credit ratings will not create a default or other unfavorable change in the 9 7/8% Notes. Senior Secured Revolving Credit Facility On April 8, 2004, we entered into a senior secured revolving credit facility led by Wells Fargo Bank, N.A. The facility, which matures on April 8, 2007, is secured by a first priority mortgage and security interest in at least 85% of our oil and gas properties, all of the ownership interests of all of our subsidiaries, and our equipment, accounts receivable, inventory, contract rights, general intangibles and other assets. The facility is also guaranteed by all of our subsidiaries. Availability under the facility, which includes a $3 million subfacility for standby letters of credit, is subject to a borrowing base that is determined at the sole discretion of the facility lenders. The initial borrowing base of the facility was $50 million, of which $30 million was available for general corporate purposes and $20 million was available for the acquisition of oil and gas properties approved by the lenders. The borrowing base is redetermined on each April 1 and October 1. Mission and the lenders each have the option to request one unscheduled interim redetermination between scheduled redetermination dates. On October 1, 2004, it was determined that there would be no change in the borrowing base. On April 8, 2004, we were advanced $21.5 million under the facility, which amount, together with a portion of the net proceeds from the offering of the 9 7/8% Notes and $25 million that was borrowed under a second lien term loan (as described below), was used to completely discharge all of our outstanding indebtedness under our prior revolving credit facility and term loan. At December 31, 2004, $15.0 million in borrowings were outstanding and $34.9 million was available for borrowing ($20.0 million of which is restricted to the acquisition of oil and gas properties approved by the lenders). Advances under the facility bear interest, at our option, at either (i) a margin (which varies from 25.0 basis points to 125.0 basis points based upon utilization of the borrowing base) over the base rate, which is the higher of (a) Wells Fargo's prime rate in effect on that day, and (b) the federal funds rate in effect on that day as announced by the Federal Reserve Bank of New York, plus 0.5%; or (ii) a margin (which varies from 175.0 basis points to 275.0 basis points based upon utilization of the borrowing base) over LIBOR. We are allowed to prepay any base rate or LIBOR loan without penalty, provided that each 36 prepayment is at least $500,000 and multiples of $100,000 in excess thereof, plus accrued and unpaid interest. Standby letters of credit may be issued under the $3 million letter of credit subfacility. We are required to pay, to the issuer of the letter of credit, with respect to each issued letter of credit, (i) a per annum letter of credit fee equal to the LIBOR margin then in effect multiplied by the face amount of such letter of credit plus (ii) an issuing fee of the greater of $500 or 12.5 basis points. The facility requires us to hedge forward, on a rolling 12-month basis, at least 50% of proved producing volumes projected to be produced over the following 12 months. We are also required to hedge forward, on a rolling 12-month basis, 25% of proved producing volumes projected to be produced over the succeeding 12-month period. Any time that we have borrowings under the facility in excess of 70% of the borrowing base available for general corporate purposes, the agent under the facility may require us to hedge an additional percentage of projected production volumes on terms acceptable to the agent. The facility also contains the following restrictions on hedging arrangements and interest rate agreements: (i) the hedge provider must be a lender under the facility or an unsecured counterparty acceptable to the agent under the facility; and (ii) total notional volume must be not more than 75% of scheduled proved producing net production quantities in any period or, with respect to interest rate agreements, notional principal amount must not exceed 75% of outstanding loans, including future reductions in the borrowing base. The facility contains the following covenants which are considered important to our operations. At December, 31, 2004, we were in compliance with each of the following covenants: - Maintain a current ratio of consolidated current assets (as defined in the facility) to consolidated current liabilities (as defined in the facility) of not less than 1.0 to 1.0; - Maintain (on an annualized basis until the passing of four fiscal quarters and thereafter on a rolling four quarter basis) an interest coverage ratio (as defined in the facility) of no less than (i) 2.50 for June 30, 2004 through December 31, 2004, (ii) 2.75 for March 31, 2005 through June 30, 2005, and (iii) 3.0 for September 30, 2005 and thereafter; - Maintain (on an annualized basis until the passing of four fiscal quarters and thereafter on a rolling four quarter basis) a leverage ratio (as defined in the facility) of no more than 3.5 for December 31, 2004 and thereafter; and - Maintain a tangible net worth (as defined in the facility) of not less than 85% of tangible net worth at March 31, 2004, plus 50% of positive net income after tax distributions, plus 100% of equity offerings after March 31, 2004, excluding any asset impairment charges. The facility also includes restrictions with respect to changes in the nature of our business; sale of all or a substantial or material part of our assets; mergers, acquisitions, reorganizations and recapitalizations; liens; guarantees; debt; leases; dividends and other distributions; investments; debt prepayments; sale-leasebacks; capital expenditures; lease expenditures; and transactions with affiliates. Second Lien Term Loan On April 8, 2004, we entered into a second lien term loan with a syndicate of lenders arranged by Guggenheim Corporate Funding, LLC. The loan, which matures on April 8, 2008, is secured by a second priority security interest in the assets securing the senior secured revolving credit facility. The facility is also guaranteed by all of our subsidiaries. On April 8, 2004, we borrowed the $25.0 million under the loan, which amount, together with a portion of the net proceeds from the offering of the 9 7/8% Notes and $21.5 million borrowed under the senior secured revolving credit facility (as described above), was used to completely discharge all of the outstanding indebtedness under the prior revolving credit facility and term loan. 37 The loan accrues interest in each monthly interest period at the rate of 30-day LIBOR plus 525 basis points per annum, payable monthly in cash. We may prepay the loan at any time after the date six months and one day after April 8, 2004 in whole or in part in multiples of $1 million at the prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if prepaid during each successive 12-month period beginning on April 9th of each year indicated below:
YEAR PREMIUM ---- ------- 2004........................................................ 102% 2005........................................................ 101% 2006 to maturity............................................ 100%
Provided, however, that no prepayment shall be made prior to the date six months and one day after April 8, 2004. The loan contains covenants that are no more restrictive than those contained in the senior secured revolving credit facility. Redeemed 10 7/8% Notes In April 1997, we issued $100 million of 10 7/8% Notes due 2007. On May 29, 2001, we issued an additional $125 million of 10 7/8% Notes with identical terms to the notes issued in April 1997 at a premium of $1.9 million. The premium, shown separately on the Consolidated Balance Sheet, was amortized as a reduction of interest expense over the life of the 10 7/8% Notes so that the effective interest rate on the additional 10 7/8% Notes was 10.5%. Interest on the 10 7/8% Notes was payable semi-annually on April 1 and October 1. On March 28, 2003, we acquired, in a private transaction with various funds affiliated with Farallon Capital Management, LLC, approximately $97.6 million in principal amount of the 10 7/8% Notes for approximately $71.7 million, plus accrued interest. Including costs of the transaction and the removal of $2.2 million of previously deferred financing costs related to the acquired 10 7/8% Notes, we recognized a $22.4 million gain on the extinguishment of the 10 7/8% Notes. In December 2003, February 2004 and March 2004, in three private transactions, we acquired $40.0 million aggregate principal amount of the 10 7/8% Notes in exchange for an aggregate of 16.75 million shares of our common stock as summarized below.
NET GAIN ON PRINCIPAL COMMON EXTINGUISHMENT OF DATE NOTE HOLDER VALUE SHARES 107/8% NOTES ---- ----------- ----------- ------------ ----------------- December 2003.......... FTVIPT -- Franklin $10 million 4.50 million $1.1 million Income Securities Fund and Franklin Custodian Funds -- Income Series February 2004.......... Stellar Funding, Ltd. $15 million 6.25 million $0.5 million March 2004............. Harbert Distressed $15 million 6.00 million $0.9 million Investment Master Fund, Ltd.
On May 10, 2004, the remaining $87.4 million of 10 7/8% Notes were redeemed at a premium of approximately $1.6 million. This premium is included in the $4.1 million ($2.6 million, net of tax) net loss on extinguishment of debt reported in the three month period ended June 30, 2004. Former Credit Facilities We were party to a $150.0 million credit facility with a syndicate of lenders. The credit facility was a revolving facility, expiring May 16, 2004, which allowed us to borrow, repay and re-borrow under the 38 facility from time to time. The total amount which might be borrowed under the facility was limited by the borrowing base periodically set by the lenders based on our oil and gas reserves and other factors deemed relevant by the lenders. The facility was re-paid in full and cancelled on March 28, 2003. On March 28, 2003, simultaneously with the acquisition of $97.6 million in principal amount of the 10 7/8% Notes, we amended and restated the credit facility with new lenders, led by Farallon Energy Lending, LLC. Deferred financing costs of $947,000 relating to the previously existing facility were charged to earnings as a reduction in the gain on extinguishment of debt. Under the amended and restated facility, we borrowed $80.0 million, the proceeds of which were used to acquire approximately $97.6 million face amount of 10 7/8% Notes, to pay accrued interest on the 10 7/8% Notes purchased, and to pay closing costs. The amended and restated facility was cancelled in April 2004 and was replaced by the "Senior Secured Revolving Credit Facility" discussed above. LIQUIDITY AND CAPITAL RESOURCES Mission's principal sources of capital for the last three years have been cash flow from operations, debt sources such as the issuance of bonds or credit facility borrowings, issuances of common stock and the sale of oil and gas properties. Our primary uses of capital have been the funding of the retirement of senior subordinated notes, exploration and development projects and property acquisitions. At December 31, 2004, we had negative working capital of $10.3 million compared to positive working capital of $16.3 million at December 31, 2003. However, our 2003 working capital was positively impacted by approximately $24.9 million of the proceeds from 2003 property sales that were held for reinvestment at December 31, 2003. On January 30, 2004, we acquired the Jalmat field for $26.6 million using these proceeds plus operating cash flow. If this cash held for reinvestment was excluded from the December 31, 2003 working capital, our working capital would have been a negative $8.6 million at that date. The unfavorable impact of increased commodity prices on the recorded commodity derivative liability balance was a significant factor in our working capital position in both 2004 and 2003. The liability represents the extent to which actual commodity prices exceed the price caps set by our hedges. Should commodity prices decrease, the liability will decline and the premium over the hedge prices that we will realize on unhedged production will also reduce. The short-term liability was $10.5 million and $8.6 million at December 31, 2004 and 2003, respectively. Since these amounts are settled out of the receipts from the sale of production, we anticipate having adequate cash inflows to settle any hedge payments when they come due while maintaining revenue near the hedge price. Other working capital components included accrued revenues that increased $3.8 million from December 31, 2003 to December 31, 2004 mainly due to higher commodity prices. Higher production volumes as a result of the Jalmat acquisition in the first half of 2004 also had an impact on the increase in accrued revenues. Almost offsetting the $3.8 million increase in accrued revenues was a $4.1 million increase in accrued liabilities between the periods. Royalties payable accounts for most of this increase. The increase in royalties payable included approximately $3.2 million of royalties that are awaiting completion of title opinions. Upon receipt of the title opinions and executed division orders, Mission will be required to make payment. This payable may increase as the well produces or decrease as title opinions are completed and royalties paid. We believe that cash flows from operating activities combined with our ability to control the timing of substantially all of our future exploration and development requirements will provide us with the flexibility and liquidity to meet our planned capital requirements for 2005. Our senior secured revolving credit facility is also available for short-term borrowings. Source of Capital: Operations Cash flow provided by operating activities totaled $58.7 million, $18.9 million, and $7.2 million for the fiscal years 2004, 2003, and 2002, respectively. Our operating cash flow is sensitive to many variables, with prices of oil, natural gas and NGLs being the most volatile. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic growth, weather and other variable factors influence 39 market conditions. We are not able to control these factors and may not be able to accurately predict prices. To mitigate some of the risk inherent in oil and natural gas prices, we hedge our oil and natural gas production by entering into commodity price swaps or collars designed to set minimum prices and maximum prices, or both, on a portion of our production. See "Item 7A-Quantitative and Qualitative Disclosures About Market Risk" for a more detailed discussion of commodity price risk and a listing of our current hedges. Source of Capital: Debt On April 8, 2004, we issued $130 million of 9 7/8 Notes due 2011, announced the redemption of our 10 7/8% senior subordinated notes due 2007, and replaced both our revolving credit facility and term loan Our outstanding balance under the 9 7/8% Notes was 130.0 million at December 31, 2004. Our outstanding balance under the 10 7/8% Notes was $117.4 million at December 31, 2003 and was $225.0 million at December 31, 2002. A portion of the net proceeds from the offering of the 9 7/8% Notes was used, on May 10, 2004, to redeem the $87.4 million aggregate principal amount of the 10 7/8% Notes that remained outstanding. On April 8, 2004, the remainder of the net proceeds from the offering of the 9 7/8% Notes, together with $21.5 million that was advanced under the new senior secured revolving credit facility (as described below) and $25.0 million that was borrowed under the new second lien term loan (as described below), was used to completely discharge all of our outstanding indebtedness under the prior revolving credit facility and term loan. Borrowings under our new senior secured revolving credit facility were $15.0 million at December 31, 2004, and $34.9 million was available for borrowing. There were no borrowings outstanding under our old credit facilities at December 31, 2003 and 2002. Availability under the new revolving credit facility, which includes a $3 million subfacility for standby letters of credit, is subject to a borrowing base that is determined at the sole discretion of the facility lenders. The initial borrowing base of the facility was $50 million, of which $30 million was available for general corporate purposes and $20 million was available for the acquisition of oil and gas properties approved by the lenders. The borrowing base is redetermined on each April 1 and October 1. Mission and the lenders each have the option to request one unscheduled interim redetermination between scheduled redetermination dates. On October 1, 2004, it was determined that there would be no change in the borrowing base. Our outstanding balance under the second lien term loan was $25.0 million at December 31, 2004. Our outstanding balance was $80.0 million in first lien term loans at December 31, 2003. There were no term loans outstanding at December 31, 2002. On April 8, 2004, we borrowed the $25.0 million under the second lien term loan, which amount, together with a portion of the net proceeds from the offering of the 9 7/8% Notes and $21.5 million borrowed under the senior secured revolving credit facility, was used to completely discharge all of the outstanding indebtedness under the prior revolving credit facility and term loan. As previously discussed under "Financing," both our 9 7/8% Notes and our senior secured revolving credit facility contain covenants limiting our activities or requiring that we maintain specific financial ratios. As of December 31, 2004, we were in compliance with all applicable covenants. Declining commodity prices or rising expenses could prevent us from meeting the credit facility covenants. In that event, we would attempt to negotiate an amendment or a waiver of the covenants from our lenders. Should the lenders fail to approve our requests, then we would attempt to obtain the funds to repay the outstanding credit facility debt through property sales or equity financing. We cannot assure you that we would be successful in completing any of these possible actions. Source of Capital: Issuance of Common Stock We issued 4.5 million shares of common stock on December 17, 2003 to FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income Series in order to acquire $10.0 million principal 40 amount value of the 10 7/8% Notes. In February 2004, we acquired $15.0 million of our 10 7/8% Notes due 2007 for 6.25 million shares of common stock in a transaction with Stellar Funding, Ltd. On March 15, 2004, we acquired an additional $15 million of our 10 7/8% Notes due 2007 from Harbert Distressed Investment Master Fund, Ltd. in exchange for 6.0 million shares of common stock. These shares of common stock were registered for resale under an effective registration statement. On April 8, 2004, we issued 312,000 shares of our common stock in lieu of cash to our financial advisors as a fee for services rendered during the debt refinancing previously discussed under "Financing." The $1.2 million fair value of this consideration was recorded as deferred financing costs. On August 4, 2004, the Compensation Committee of Mission's Board of Directors granted to Robert L. Cavnar, Chairman, President and CEO of Mission, a nonqualified option to acquire 800,000 shares of our common stock. We granted this option to replace the grant of 800,000 share appreciation rights made to Mr. Cavnar in November 2003. The option was granted under the 2004 Incentive Plan, has a term of 10 years, is fully vested and has a strike price of $0.55 per share, which is the same exercise price as the surrendered share appreciation rights. As a result of this option having an exercise price below the market value for our common stock at the time of issuance, we recognized a non-cash compensation expense of approximately $4.1 million ($2.6 million, net of tax) in the third quarter of 2004. Source of Capital: Sale of Properties We continue to evaluate and assess our property portfolio and capital needs, and we may from time to time sell certain properties as appropriate. Net proceeds from the sales of oil and gas properties in 2004, 2003 and 2002 were approximately $13.0 million, $28.1 million, and $60.4 million, respectively. Net proceeds are gross proceeds adjusted for transaction costs and interim operations. Use of Capital: Exploration and Development Mission's expenditures for exploration, including land and seismic costs, and development of domestic oil and gas properties totaled $45.4 million, $33.4 million, and $20.6 million for the fiscal years 2004, 2003, and 2002, respectively. Our capital budget for 2005 is $71 million using estimated prices of $35.00 per BBL and $5.50 per MMBTU. Approximately 54% of the total is planned for development projects, while 28% is planned for exploration. The remaining 18% is planned for seismic data, land and land-related assets and corporate assets. Based upon the level of funding needed for development, the level of exploratory spending could be modified to meet the budget in total. This capital budget represents the largest planned use of our available operating cash flow. We believe that cash flows from operating activities combined with our ability to control the timing of substantially all of our future exploration and development requirements will provide us with the flexibility and liquidity to meet our planned capital requirements for 2005. Our intent is to apply less than our discretionary cash flow to capital projects in 2005. The budget may be modified throughout the year based on our projections of cash flow; however, due to the timing of our capital programs, we may spend more than our cash flow in individual quarters. Use of Capital: Acquisitions and Other Corporate Assets In 2004, spending for oil and gas property acquisitions was approximately $41.5 million. The purchase of a 94.5% working interest in the Jalmat field for $30.2 million along with the purchase of additional working interests in the Chocolate Bayou, Southwest Lake Boeuf, Backridge and West Lake Verret fields for approximately $11 million accounted for all of the 2004 property acquisitions. In 2003, spending for oil and gas property acquisitions was approximately $1.6 million. The most significant individual acquisition was that of an additional interest in High Island Block A-553 for approximately $621,000. We did not make any significant oil and gas property acquisitions during 2002. We continuously review acquisition opportunities and would first consider utilizing operating cash flows to make a desired acquisition. For larger acquisitions, our credit facility or the issuance of equity 41 securities could provide the necessary funds; however, we cannot assure you that either of these sources would be able to provide funds adequate to complete every desired acquisition. We invested approximately $1.2 million in other corporate assets during 2004. The majority of this investment went towards the purchase and implementation of an upgraded revenue and general accounting system. We invested approximately $1.0 million in other corporate assets during 2003. These assets include a new computer system for land records and office expansion to accommodate our growing workforce. Use of Capital: Contractual Obligations and Commercial Commitments The tables below illustrate our significant contractual obligations and other commercial commitments as of December 31, 2004 (amounts in thousands):
CONTRACTUAL CASH OBLIGATIONS: TOTAL 2005 2006 2007 2008 2009 THEREAFTER ----------------------------- -------- ------- ------- ------- ------- ------- ---------- Long Term Debt*............. $210,234 $12,837 $12,838 $12,837 $12,838 $12,837 $146,047 Term Loan*.................. 31,254 1,927 1,926 1,926 25,475 -- -- Operating Leases............ 1,723 962 718 43 -- -- -- Firm Transport Agreement.... 4,525 1,498 1,435 1,320 272 -- -- -------- ------- ------- ------- ------- ------- -------- $247,736 $17,224 $16,917 $16,126 $38,585 $12,837 $146,047 ======== ======= ======= ======= ======= ======= ======== Other Commercial Commitments: Credit Facility*............ $ 16,839 $ 818 $ 819 $15,202 -- -- -- Other....................... 4,270 4,114 156 -- -- -- -- -------- ------- ------- ------- ------- ------- -------- Total Contractual Obligations................. $268,845 $22,156 $17,892 $31,328 $38,585 $12,837 $146,047 ======== ======= ======= ======= ======= ======= ========
--------------- * Includes principal and interest. CRITICAL ACCOUNTING POLICIES In response to SEC Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we identified those policies of particular importance to the portrayal of our financial position and results of operations and those policies that require our management to apply significant judgment. We believe these critical accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements. FULL COST METHOD OF ACCOUNTING FOR OIL AND GAS ASSETS We use the full cost method of accounting for investments in oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas reserves are capitalized as incurred into a "full cost pool". Under the full cost method, a portion of employee-related costs may be capitalized in the full cost pool if they are directly identified with acquisition, exploration and development activities. Generally, salaries and benefits are allocated based upon time spent on projects. Amounts capitalized can be significant when exploration and major development activities increase. We deplete the capitalized costs in the full cost pool, plus estimated future expenditures to develop reserves and asset retirement cost, on a prospective basis using the units of production method based upon the ratio of current production to total proved reserves. Depreciation, depletion and amortization is a significant component of our net income. Proportionally, it represented 34% and 38% of our total oil and gas revenues in the years ended December 31, 2004 and 2003 respectively. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate. If during 2005, our reserves increase by 10%, our depletion per MCFE would decrease approximately $0.16, or 9%; however, a 10% decrease in reserves will have a 11% impact, increasing depletion per MCFE by approximately $0.19. 42 Both the volume of proved reserves and the estimated future expenditures used for the depletion calculation are obtained from the reserve estimates prepared by independent reserve engineers. These reserve estimates rely upon both the engineers' quantitative and subjective analysis of various data, such as engineering data, production trends and forecasts, estimated future spending and the timing of spending. Finally, estimated production costs and commodity prices are added to the assessment in order to determine whether the estimated reserves have any value. Reserves that cannot be produced and sold at a profit are not included in the estimated total proved reserves; therefore the quantity of reserves can increase or decrease as oil and gas prices change. See "Risk Factors: Risks Related to Our Business, Industry and Strategy" for general cautions concerning the reliability of reserve and future net revenue estimates by reserve engineers. The full cost method requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves adjusted for taxes, using a 10% discount rate. To the extent that our capitalized costs (net of depreciation, depletion, amortization, and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and gas properties is not reversible at a later date even if oil and gas prices increase. No such impairment was required in the years ended December 31, 2004, 2003 and 2002. While the difficulty in estimating proved reserves could cause the likelihood of a ceiling impairment to be difficult to predict, the impact of changes in oil and gas prices is most significant. In general, the ceiling is lower when prices are lower. Oil and gas prices at the end of the period are applied to the estimated reserves, then costs are deducted to arrive at future net revenues, which are then discounted at 10% to arrive at the discounted present value of proved reserves. Additionally, we adjust the estimated future revenues for the impact of our existing cash flow commodity hedges. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on Mission's assessment of future prices or costs, but rather are based on prices and costs in effect as of the end the period. Because the ceiling calculation dictates that prices in effect as of the last day of the period be held constant, the resulting value is rarely indicative of the true fair value of our reserves. Oil and natural gas prices have historically been variable and, on any particular day at the end of a period, can be either substantially higher or lower than our long-term price forecast, which we feel is more indicative of our reserve value. You should not view full cost ceiling impairments caused by fluctuating prices, as opposed to reductions in reserve volumes, as an absolute indicator of a reduction in the ultimate value of our reserves. Oil and gas prices used in the ceiling calculation at December 31, 2004 were $43.33 per barrel and $6.18 per MMBTU. A significant reduction in these prices at a future measurement date could trigger a full cost ceiling impairment. As an illustration, had oil and gas prices at December 31, 2004 been 10% lower, we would have been 76% closer to a ceiling impairment. DERIVATIVE INSTRUMENTS ACCOUNTING All of our commodity derivative instruments represent hedges of the price of future oil and natural gas production. We estimate the fair values of our hedges at the end of each reporting period. The estimated fair values of our commodity derivative instruments are recorded in the consolidated Balance Sheet as assets or liabilities as appropriate. For effective hedges, we record the change in the fair value of the hedge instruments to other comprehensive income, a component of stockholders' equity, until the hedged oil or natural gas quantities are produced. Any ineffectiveness in our hedges, which could represent either gains or losses, is reported when calculated as part of the interest and other income line of the Statement of Operations 43 Estimating the fair values of commodity hedge derivatives requires complex calculations, including the use of a discounted cash flow technique and our subjective judgment in selecting an appropriate discount rate. In addition, the calculation uses future NYMEX prices, which although posted for trading purposes, are merely the market consensus of forecast price trends. The results of our fair value calculation cannot be expected to represent exactly the fair value of our commodity hedges. We currently use a software product from an outside vendor to calculate the fair value of our hedges. This vendor provides the necessary futures prices and the calculated volatility in those prices to us daily. The software is programmed to apply a consistent discounted cash flow technique, using these variables and a discount rate derived from prevailing interest rates. This software is successfully used by several of our peers. Its methods are in compliance with the requirements of SFAS No. 133 and have been reviewed by a national accounting firm. REVENUE RECOGNITION Mission records revenues from sales of crude oil and natural gas when delivery to the customer has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred. We may share ownership with other producers in certain properties. In this case, we use the sales method to account for sales of production. It is customary in the industry for various working interest partners to sell more or less than their entitled share of natural gas production, creating gas imbalances. Under the sales method, gas sales are recorded when revenue checks are received or are receivable on the accrual basis. Typically no provision is made on the Balance Sheet to account for potential amounts due to or from Mission related to gas imbalances. If the gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions, a payable or a receivable, as appropriate, should be recorded equal to the net value of the imbalance. As of December 31, 2004, we had recorded a net liability of approximately $850,000, representing approximately 500,000 MCF at an average price of $1.70 per MCF, related to imbalances on properties at or nearing depletion. The net liability accrued as of December 31, 2003, was $1.1 million, representing approximately 379,000 MCF at an average price of $2.95 per MCF. We value gas imbalances using the price at which the imbalance originated, if required by the gas balancing agreement, or we use the current price where there is no gas balancing agreement available. Reserve changes on any fields that have imbalances could change this liability. We do not anticipate the settlement of gas imbalances to adversely impact our financial condition in the future. Settlements are typically negotiated, so the per Mcf price for which imbalances are settled could differ among wells and even among owners in one well. Exclusive of the liability recorded for properties at or nearing depletion (see discussion above), our unrecorded imbalance, valued at current prices would be approximately a $593,000 liability. ASSET RETIREMENT, IMPAIRMENT OR DISPOSAL We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" effective January 1, 2003. Previously our estimate of future plugging and abandonment and dismantlement costs was charged to income by being included in the capitalized costs that we depleted using the unit of production method. SFAS No. 143 requires us to record a liability for the fair value of our estimated asset retirement obligation, primarily comprised of our plugging and abandonment liabilities, in the period in which it is incurred. Upon initial implementation, we estimated asset retirement costs for all of our assets as of such date, inflation adjusted those costs to the forecast abandonment date, discounted that amount back to the date we acquired the asset and recorded an asset retirement liability in that amount with a corresponding addition to our asset value. Then we computed all depletion previously taken on future plugging and abandonment costs, and reversed that depletion. Finally, we accreted the liability to present day and computed historical depletion on the new asset retirement cost through the adoption date. Any income effect of this initial implementation was reflected as a change in accounting method on our Statement of Operations. 44 After initial implementation, we reduce the liability as abandonment costs are incurred. As new wells are drilled or purchased their initial asset retirement cost and liability will be calculated and recorded. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our risk-adjusted rate. The risk-adjusted rate is re-evaluated annually so the liability could have layers of valuation. We accrete the liability in these layers using the appropriate period and interest rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost; therefore, abandonment costs will almost always approximate the estimate. We have developed a process through which to track and monitor the obligations for each asset. When wells are sold the related liability and asset cost are removed from the Balance Sheet. Any difference between the two remains in the full cost pool. SFAS No. 143 does not specifically address the proper accounting to be applied by a full cost method company when properties are sold. A May 23, 2003 letter to the FASB and the SEC from a group of concerned companies makes inquiries and outlines possible alternatives, including our current treatment. Should a clarification be issued, there is a chance that Mission's treatment will be required to change and the entire $3.5 million credit that is in our full cost pool for 2004 would be included in income. As with previously discussed estimates, the estimation of our initial liability and its subsequent remeasurements are dependent upon many variables. We attempt to limit the impact of management's judgment on these variables by using the input of qualified third parties when possible. We engaged an independent engineering firm to evaluate our properties annually and to provide us with estimates of abandonment costs. We use the remaining estimated useful life from the year-end Netherland, Sewell & Associates, Inc. reserve report in estimating when abandonment could be expected for each property. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make the most accurate estimation possible. Should either the estimated life or the estimated abandonment costs of a property change upon subsequent review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our risked rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. INCOME TAXES Mission has accumulated substantial income tax deductions that have not yet been used to reduce cash income taxes actually paid with the filing of our income tax returns. These accumulated deductions are commonly referred to as "net operating loss carryforwards" or "NOLs". Our NOLs are, subject to a number of restrictions, available to reduce cash taxes that may become owed in future years. In accordance with the accounting for income taxes under SFAS No. 109, we record a deferred tax asset for our NOLs. If we estimate that some or all of our NOLs are more likely than not going to expire or otherwise not be utilized to reduce future tax, we record a valuation allowance to remove the benefit of those NOLs from our financial statements One of the restrictions on the future use of NOLs is contained in Section 382 of the Internal Revenue Code. In general, Section 382 provides that the amount of existing NOLs that may be used to offset future taxable income after the occurrence of an "ownership change" (as defined solely for Section 382 purposes) is limited to an amount that is determined, in part, by the fair market value of the enterprise at the time the ownership change occurred. The fair market value of the enterprise's individual assets and the timing in which the value of those assets are realized are also factors that impact the amount of NOLs available under Section 382 ("382 Limitation"). 45 As a result of our issuance of common stock in exchange for the retirement of a portion of our 10 7/8% senior subordinated notes in December 2003, we experienced an "ownership change" as defined under Section 382. Consequently, we have included the estimated impact that a 382 Limitation may have upon the future availability of our NOLs as part of our evaluation under SFAS 109. Consistent with previously described estimates, our estimation of the future benefit of our NOLs is dependent upon many variables and is subject to change. Management's judgment on these variables considers, in part, the input of qualified third parties when possible. To assist in the determination of the impact (if any) that the 382 Limitations may have upon the Company's NOLs, we have used information derived from a) the public equity markets b) data provided by an independent reserve engineering firm and c) opinions from an independent appraisal firm. We have engaged an international independent public accounting firm to assist us in applying the numerous and complicated tax law requirements. However, despite our attempt to make the most accurate estimates possible, the ultimate utilization of our NOLs is highly dependent upon our actual production and the realization of taxable income in future periods. OTHER MATTERS NEW ACCOUNTING PRONOUNCEMENTS Staff Accounting Bulletin ("SAB") No. 106, regarding the application of FASB Statement No. 143, Accounting for Asset Retirement Obligations, by oil and gas producing companies following the full cost accounting method was issued in September 2004. SAB 106 provided an interpretation of how a company, after adopting Statement 143, should compute the full cost ceiling to avoid double-counting the expected future cash outflows associated with asset retirement costs. The provisions of this interpretation have been applied by the Company and has no impact on the financial statements. SFAS No. 123R, Share-Based Payments was issued in December 2004. SFAS No. 123R requires public companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period. SFAS No. 123R amends the original SFAS No. 123 and 95 that had allowed companies to choose between expensing stock options or showing pro forma disclosure only. SFAS No. 123R becomes effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The impact of SFAS No. 123R is dependent upon grants issued and; therefore, cannot be estimated at this time. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Mission is exposed to market risk, including adverse changes in commodity prices and interest rates. To the extent that we use derivative instruments to mitigate these risks, we are also exposed to credit risk. COMMODITY PRICE RISK Mission produces and sells crude oil, natural gas and natural gas liquids. As a result, our operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. We periodically seek to reduce our exposure to price volatility by hedging a portion of production through swaps, options and other commodity derivative instruments. A combination of options, structured as a collar, is our preferred hedge instrument because there are no up-front costs and protection is given against low prices. These collars assure that the NYMEX prices we receive on the hedged production will be no lower than the price floor and no higher than the price ceiling. The oil hedges that are swaps fix the price to be received. Our 12-month average realized price, excluding hedges, for natural gas was $0.12 per MCF less than the NYMEX MMBTU price. Our 12-month realized price, excluding hedges, for oil was $1.47 per BBL less than NYMEX. Realized prices differ from NYMEX due to factors such as the location of the property, the heating content of natural gas and the quality of oil. The gas differential stated above excludes the impact of the Mist field gas production, which is sold at an annually fixed price. 46 In May 2002 several existing oil collars were cancelled. New swaps and collars hedging forecast oil production were acquired. We paid approximately $3.3 million, the fair value of the previous oil price collars at that time, to counter parties in order to cancel the transactions. By removing the price volatility from hedged volumes of oil and natural gas production, we have mitigated, but not eliminated, the potential negative effect of declining prices on our operating cash flow. The potential for increased operating cash flow due to increasing prices has also been reduced. If all our commodity hedges were to settle at December 31, 2004 prices, our cash flows would decrease by $11.9 million; however the actual settlement of our hedges will increase or decrease cash flows over the period of the hedges at varying prices. The following tables detail our commodity hedges as of March 7, 2005. OIL HEDGES
NYMEX NYMEX BBLS PRICE FLOOR PRICE CEILING PERIOD PER DAY TOTAL BBLS TYPE AVG. AVG. ------ ------- ---------- ---- ----------- ------------- First Qtr. 2005................... 2,500 225,000 Collar $28.71 $32.78 Second Qtr. 2005.................. 2,500 227,500 Collar $32.54 $36.47 Third Qtr. 2005................... 2,500 230,000 Collar $32.06 $35.71 Fourth Qtr. 2005.................. 2,500 230,000 Collar $31.53 $35.18 First Qtr. 2006................... 1,750 157,500 Collar $34.49 $48.20 Second Qtr. 2006.................. 1,750 159,250 Collar $34.16 $46.86 Third Qtr. 2006................... 1,750 161,000 Collar $33.58 $46.07 Fourth Qtr. 2006.................. 1,750 161,000 Collar $33.33 $45.08
GAS HEDGES
NYMEX NYMEX MMBTU PRICE FLOOR PRICE CEILING PERIOD PER DAY TOTAL MMBTU TYPE AVG. AVG. ------ ------- ----------- ---- ----------- ------------- First Qtr. 2005............... 15,500 1,395,000 Collar $5.00 $9.75 Second Qtr. 2005.............. 14,000 1,274,000 Collar $5.02 $6.82 Third Qtr. 2005............... 14,000 1,288,000 Collar $5.02 $6.86 Fourth Qtr. 2005.............. 14,000 1,288,000 Collar $5.06 $7.47 First Qtr. 2006............... 7,500 675,000 Collar $5.84 $9.57 Second Qtr. 2006.............. 5,500 500,500 Collar $5.50 $7.43 Third Qtr. 2006............... 5,500 506,000 Collar $5.50 $7.40 Fourth Qtr. 2006.............. 5,500 506,000 Collar $5.73 $8.23
CREDIT RISK These commodity hedges expose Mission to counter party credit risk to the extent the counter party is unable to meet its monthly settlement commitment to us. We believe that we select creditworthy counter parties to our hedge transactions. Each of our counter parties have long-term senior unsecured debt ratings of at least A/A2 by Standard & Poor's or Moody's. INTEREST RATE RISK Our senior secured revolving credit facility and term loan have floating interest rates and as such expose us to interest rate risk. If interest rates were to increase 10% over their current levels, and at our current level of borrowing, our annualized interest expense would increase $258,000 or 1.7%. We have considered, but have not yet entered into, derivative transactions designed to mitigate interest rate risk. The Company paid $1.3 million in February 2003 to cancel an interest rate swap under which Mission received a fixed interest rate and paid a floating interest rate. The swap originated in 1998 and had a notional value of $80 million. 47 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PAGE NUMBER ----------- Report of Independent Registered Public Accounting Firm..... 49 Attestation Report on Management's Assessment of the Company's Internal Controls over Financial Reporting...... 50 Management's Annual Report on Internal Controls over Financial Reporting....................................... 52 Financial Statements: Consolidated Balance Sheets as of December 31, 2004 and 2003...................................................... 53 Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002.......................... 55 Consolidated Statements of Changes in Stockholders' Equity and Comprehensive Income or Loss For the Years Ended December 31, 2004, 2003 and 2002.......................... 56 Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002.......................... 57 Notes to Consolidated Financial Statements.................. 58
48 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders Mission Resources Corporation: We have audited the accompanying consolidated balance sheets of Mission Resources Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders' equity and comprehensive income or loss, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mission Resources Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. As discussed in note 2 to the consolidated financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. As discussed in note 2 to the consolidated financial statements, effective January 1, 2002, the Company adopted the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Mission Resources Corporation's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 7, 2005 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting. KPMG LLP Houston, Texas March 7, 2005 49 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders Mission Resources Corporation: We have audited management's assessment, included in the accompanying report, "Management's Annual Report on Internal Controls over Financial Reporting", that Mission Resources Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Mission Resources Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assessment that Mission Resources Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Mission Resources Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 50 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Mission Resources Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders' equity and comprehensive income or loss, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 7, 2005 expressed an unqualified opinion on those consolidated financial statements. KPMG LLP Houston, Texas March 7, 2005 51 MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING The Board of Directors and Stockholders Mission Resources Corporation and Subsidiaries: Management of Mission Resources Corporation (the "Company") is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and board of directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control -- Integrated Framework. As a result of this assessment, management believes that the Company's internal control over financial reporting as of December 31, 2004 is effective, based on those criteria. KPMG LLP, the independent registered public accounting firm who also audited the Company's consolidated financial statements, has issued an attestation report on management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2004. KPMG's attestation report on management's assessment of the Company's internal control over financial reporting appears on page 52 hereof. Management Mission Resources Corporation Houston, Texas March 7, 2005 52 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, DECEMBER 31, 2004 2003 --------------- --------------- (AMOUNTS IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................... $ 5,975 $ 2,234 Cash held for reinvestment.................................. -- 24,877 Accounts receivable......................................... 4,953 6,327 Accrued revenues............................................ 12,175 8,417 Current deferred income taxes............................... 3,644 3,076 Prepaid expenses and other.................................. 2,039 2,523 --------- --------- Total current assets...................................... 28,786 47,454 --------- --------- PROPERTY, PLANT AND EQUIPMENT, at cost: Oil and gas properties (full cost) Unproved properties of $8,858 and $6,123 excluded from amortization as of December 31,2004 and 2003, respectively................... 891,147 805,900 Asset retirement cost....................................... 18,034 10,987 Accumulated depreciation, depletion and amortization........ (571,254) (514,759) --------- --------- Net property, plant and equipment......................... 337,927 302,128 Leasehold, furniture and equipment.......................... 5,610 4,405 Accumulated depreciation.................................... (2,831) (2,065) --------- --------- Net leasehold, furniture and equipment.................... 2,779 2,340 --------- --------- OTHER ASSETS................................................ 8,411 5,404 --------- --------- $ 377,903 $ 357,326 ========= =========
See Notes to Consolidated Financial Statements. 53 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
DECEMBER 31, DECEMBER 31, 2004 2003 --------------- --------------- (AMOUNTS IN THOUSANDS, EXCEPT SHARE INFORMATION) LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable............................................ $ 9,470 $ 8,864 Accrued liabilities......................................... 13,207 9,131 Interest payable............................................ 3,381 3,425 Commodity derivative liabilities............................ 10,477 8,597 Current portion of asset retirement obligation.............. 2,512 1,160 -------- -------- Total current liabilities................................. 39,047 31,177 -------- -------- LONG-TERM DEBT: Term loan facility.......................................... 25,000 80,000 Revolving credit facility................................... 15,000 -- Senior 9 7/8% notes due 2011................................ 130,000 -- Senior subordinated 10 7/8% Notes due 2007, plus $1,070 of unamortized premium....................................... -- 118,496 -------- -------- Total long-term debt...................................... 170,000 198,496 LONG-TERM LIABILITIES: Commodity derivative liabilities, excluding current portion................................................... 1,482 80 Deferred income taxes....................................... 20,003 20,346 Other liabilities........................................... -- 130 Asset retirement obligation, excluding current portion...... 35,366 32,157 -------- -------- Total long-term liabilities............................... 56,851 52,713 STOCKHOLDERS' EQUITY: Preferred stock, $0.01 par value, 5,000,000 shares authorized; none issued or outstanding at December 31, 2004 and 2003............................................. -- -- Common stock, $0.01 par value, 60,000,000 shares authorized, 41,416,671 and 28,017,636 shares issued at December 31, 2004 and December 31, 2003, respectively.................. 418 284 Additional paid-in capital.................................. 208,740 172,532 Retained deficit............................................ (87,283) (90,232) Treasury stock, at cost, of 389,323 shares at December 31, 2004 and 2003............................................. (1,937) (1,937) Other comprehensive income (loss), net of taxes............. (7,933) (5,707) -------- -------- Total stockholders' equity................................ 112,005 74,940 -------- -------- $377,903 $357,326 ======== ========
See Notes to Consolidated Financial Statements. 54 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, DECEMBER 31, 2004 2003 2002 --------------- --------------- --------------- (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) REVENUES: Oil and gas revenues.................................. $128,707 $99,357 $112,879 Gain (loss) on extinguishment of debt................. (2,606) 23,476 -- Interest and other income (expense)................... (461) 1,141 (7,415) -------- ------- -------- 125,640 123,974 105,464 -------- ------- -------- COSTS AND EXPENSES: Lease operating expenses.............................. 29,060 32,728 43,222 Taxes other than income............................... 9,400 8,251 9,246 Transportation costs.................................. 346 349 834 Asset retirement obligation accretion expense......... 1,202 1,263 -- Depreciation, depletion and amortization.............. 44,229 38,501 43,291 Impairment expense.................................... -- -- 16,679 Loss on sale of assets................................ -- -- 2,645 General and administrative expenses................... 16,871 10,856 12,758 Interest and related expenses......................... 19,818 25,565 26,853 -------- ------- -------- 120,926 117,513 155,528 -------- ------- -------- Income (loss) before income taxes and cumulative effect of a change in accounting................... 4,714 6,461 (50,064) Income tax expense (benefit).......................... 1,765 2,358 (11,580) -------- ------- -------- Income (loss) before cumulative effect of a change in accounting method.................................. 2,949 4,103 (38,484) -------- ------- -------- Cumulative effect of a change in accounting method, net of tax of $935................................. -- 1,736 -- -------- ------- -------- Net income (loss)..................................... $ 2,949 $ 2,367 $(38,484) ======== ======= ======== Income (loss) per share before cumulative effect of a change in accounting method........................ $ 0.08 $ 0.17 $ (1.63) ======== ======= ======== Income (loss) per share before cumulative effect of a change in accounting method -- diluted............. $ 0.07 $ 0.17 $ (1.63) ======== ======= ======== Net income (loss) per share........................... $ 0.08 $ 0.10 $ (1.63) ======== ======= ======== Net income (loss) per share -- diluted................ $ 0.07 $ 0.10 $ (1.63) ======== ======= ======== Weighted average common shares Outstanding............ 38,529 23,696 23,586 ======== ======= ======== Weighted average common shares outstanding -- diluted............................. 40,456 24,737 23,586 ======== ======= ========
See Notes to Consolidated Financial Statements. 55 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME OR LOSS
OTHER COMMON STOCK PREFERRED STOCK ADDITIONAL COMPREHENSIVE TREASURY STOCK --------------- ------------------- PAID-IN INCOME RETAINED ---------------- SHARES AMOUNT SHARES AMOUNT CAPITAL (LOSS) DEFICIT SHARES AMOUNT TOTAL ------ ------ -------- -------- ---------- ------------- -------- ------ ------- -------- (AMOUNTS IN THOUSANDS) December 31, 2001...... 23,897 $239 -- $ -- $163,735 $ 2,286 $(54,115) (311) $(1,905)$110,240 Compensation expense -- stock options........ -- -- -- -- 102 -- -- -- -- 102 Comprehensive loss: Net loss............. -- -- -- -- -- -- (38,484) -- -- (38,484) Hedge activity....... -- -- -- -- -- (6,481) -- -- -- (6,481) -------- Total comprehensive Loss................. (44,965) ------ ---- -------- -------- -------- ------- -------- ---- ------- -------- December 31, 2002...... 23,897 239 -- -- 163,837 (4,195) (92,599) (311) (1,905) 65,377 Stock options exercised and related tax effects.............. 10 -- -- -- 10 -- -- -- -- 10 Issuance of common stock related to debt retirement........... 4,500 45 -- -- 8,685 -- -- -- -- 8,730 Acquired treasury stock................ -- -- -- -- -- -- -- (78) (32) (32) Comprehensive income: Net income........... -- -- -- -- -- -- 2,367 -- -- 2,367 Hedge activity....... -- -- -- -- -- (1,512) -- -- -- (1,512) -------- Total comprehensive income............... -- -- -- -- -- -- -- -- -- 855 ------ ---- -------- -------- -------- ------- -------- ---- ------- -------- December 31, 2003...... 28,407 284 -- -- 172,532 (5,707) (90,232) (389) (1,937) 74,940 Stock options exercised and related tax effects.............. 837 8 -- -- 2,772 -- -- -- -- 2,780 Issuance of common stock related to debt retirement........... 12,562 126 -- -- 29,427 -- -- -- -- 29,553 Stock issuance fees.... -- -- -- -- (111) -- -- -- -- (111) Compensation expense -- stock options........ -- -- -- -- 4,120 -- -- -- -- 4,120 Comprehensive income: Net income........... -- -- -- -- -- -- 2,949 -- -- 2,949 Hedge activity....... -- -- -- -- -- (2,226) -- -- -- (2,226) -------- Total comprehensive income............... -- -- -- -- -- -- -- -- -- 723 ------ ---- -------- -------- -------- ------- -------- ---- ------- -------- December 31, 2004...... 41,806 $418 -- $ -- $208,740 $(7,933) $(87,283) (389) $(1,937)$112,005 ====== ==== ======== ======== ======== ======= ======== ==== ======= ========
See Notes to Consolidated Financial Statements. 56 MISSION RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, DECEMBER 31, 2004 2003 2002 --------------- --------------- --------------- (AMOUNTS IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)........................................... $ 2,949 $ 2,367 $(38,484) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization.................. 44,229 38,501 43,291 Gain on interest rate swap................................ -- (520) (2,248) Loss (gain) on commodity hedges........................... (108) (985) 9,050 Cumulative effect of a change in accounting method, net of deferred tax............................................ -- 1,736 -- Amortization of deferred financing costs and bond premium................................................. 1,648 2,160 2,794 Loss (gain) on extinguishment of debt..................... 2,606 (23,476) -- Asset retirement accretion expense........................ 1,202 1,263 -- Impairment expense........................................ -- -- 16,679 Compensation expense-stock options........................ 4,120 -- 102 Deferred taxes............................................ 1,468 2,082 (10,846) Other..................................................... 388 (267) 553 Changes in assets and liabilities, net of acquisition: Accounts receivable and accrued revenues.................. (2,825) 4,188 4,364 Prepaid expenses and other................................ 440 (272) 2,473 Accounts payable and accrued liabilities.................. 4,500 (4,248) (17,913) Abandonment costs......................................... (2,028) (3,550) (2,593) Other..................................................... 89 (90) -- --------- -------- -------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES............. 58,678 18,889 7,222 --------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions of oil and gas properties...................... (41,488) (1,570) (850) Proceeds on sale of oil and gas properties, net............. 13,030 28,090 60,396 Proceeds on sale of other assets, net....................... -- 850 -- Additions to oil and gas properties......................... (45,420) (32,893) (20,589) Additions to leasehold, furniture and equipment............. (1,205) (930) (198) Distribution from equity investment......................... 178 -- -- --------- -------- -------- NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES... (74,905) (6,453) 38,759 --------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings.................................... 201,500 80,000 21,000 Repayment of borrowings..................................... (200,511) (71,700) (56,000) Net proceeds from issuance of common stock.................. 1,463 4 -- Cash held for reinvestment.................................. 24,877 (24,877) -- Credit facility costs....................................... (7,361) (4,976) (237) --------- -------- -------- NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES... 19,968 (21,549) (35,237) --------- -------- -------- Net increase (decrease) in cash and cash equivalents........ 3,741 (9,113) 10,744 Cash and cash equivalents at beginning of period............ 2,234 11,347 603 --------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 5,975 $ 2,234 $ 11,347 ========= ======== ========
See Notes to Consolidated Financial Statements. 57 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION Mission Resources Corporation (the "Company" or "Mission") is an independent oil and gas exploration and production company. We develop and produce crude oil and natural gas. Mission's balanced portfolio comprises assets located in the Permian Basin (West Texas and Southeast New Mexico), along the Texas and Louisiana Gulf Coast and in the Gulf of Mexico. Our operational focus is on property enhancement through development drilling, operating cost reduction, low to moderate risk exploration, asset redeployment and acquisitions of properties in the right circumstances. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Mission Resources Corporation and its wholly owned subsidiaries. Mission owns a 26.6% interest in the White Shoal Pipeline Corporation that is accounted for using the equity method. Mission's net investment of approximately $237,000 at December 31, 2004 is included in the other assets line of the Consolidated Balance Sheet. Mission had a 10.1% ownership in the East Texas Salt Water Disposal Company that was accounted for using the cost method. It was reported at $861,000 in the other assets line of the Consolidated Balance Sheet at December 31, 2002. This interest was sold in December 2003 in connection with the sale of several oil and gas properties in the East Texas area. OIL AND GAS PROPERTIES Full Cost Pool -- The Company utilizes the full cost method to account for its investment in oil and gas properties. Under this method, all costs of acquisition, exploration and development of oil and gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs and tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and gas properties when incurred. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen and engineers directly involved in acquisition, exploration and development activities, and amounted to $2.1 million, $1.8 million, and $1.3 million in the years ended December 31, 2004, 2003 and 2002, respectively Depletion -- The cost of oil and gas properties, the estimated future expenditures to develop proved reserves, and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and gas reserves as estimated by independent engineering consultants as of the beginning of the reporting period. Depletion expense per thousand cubic feet of gas equivalent ("MCFE") was approximately $1.80 in 2004, $1.65 in 2003, and $1.29 in 2002. 58 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Unproved Property Costs -- Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or whether impairment has occurred. The following table shows, by category of cost and date incurred, the domestic unproved property costs excluded from amortization (amounts in thousands):
TOTAL AT LEASEHOLD EXPLORATION DECEMBER 31, COSTS INCURRED DURING PERIODS ENDED: COSTS COSTS 2004 ------------------------------------ --------- ----------- ------------ December 31, 2004...................................... $1,626 $2,997 $4,623 December 31, 2003...................................... 261 -- 261 December 31, 2002...................................... 1,265 -- 1,265 December 31, 2001...................................... 1,469 -- 1,469 Prior.................................................. 1,240 -- 1,240 ------ ------ ------ $5,861 $2,997 $8,858 ====== ====== ======
Such unproved property costs fall into four broad categories: - Material projects which are in the last one to two years of seismic evaluation; - Material projects currently being marketed to third parties; - Leasehold and seismic costs for projects not yet evaluated; and - Drilling and completion costs for projects in progress at year-end that have not resulted in the recognition of reserves at December 31, 2004. This category of costs will transfer into the full cost pool in 2005. Approximately $1.2 million, $2.8 million, and $2.2 million were evaluated and moved to the full cost pool in 2004, 2003 and 2002, respectively. Sales of Properties -- Dispositions of oil and gas properties held in the full cost pool are recorded as adjustments to net capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas. Net proceeds from property sales of $13.0 million, $28.1 million and $60.4 million were recorded as adjustments to net capitalized costs during the years 2004, 2003 and 2002, respectively. Impairment -- To the extent that capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization, exceed the discounted future net revenues of proved oil and gas reserves net of deferred taxes, such excess capitalized costs would be charged to operations as an impairment. Oil and gas prices as of December 31, 2004 were $43.33 per barrel of oil (NYMEX WTI Cushing) and $6.18 per MMBTU of gas (NYMEX Henry Hub). Such closing prices, adjusted to the wellhead to reflect adjustments for marketing, quality and heating content, were used to determine discounted future net revenues for the Company. In addition, the Company adjusted discounted future net revenues to reflect the potential impact of its commodity hedges that qualify for hedge accounting under SFAS No. 133. This adjustment was calculated by taking the difference between the closing NYMEX spot prices and the price ceiling on the Company's hedges multiplied by the hedged volumes that were included in proved reserves. This calculation resulted in a decrease in discounted future net revenues of $11.0 million because prices prevailing at December 31, 2004 were higher than most of the Company's price ceilings. The Company's capitalized costs were not in excess of these adjusted discounted future net revenues as of December 31, 2004 and 2003; therefore no impairment was required. 59 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Any reference to oil and gas reserve information in the Notes to Consolidated Financial Statements is unaudited. ROYALTIES PAYABLE The accrued liabilities line of the Consolidated Balance Sheet includes approximately $3.2 million of royalties that are awaiting completion of title opinions. Upon receipt of the title opinions and executed division orders, Mission will be required to make payment. This liability may increase in size as the well produces or decrease as title opinions are completed and royalties paid. Typically, royalties are paid within one to two months after the production is sold. REVENUE RECOGNITION AND GAS IMBALANCES Revenues are recognized and accrued as production occurs. In 2002, no one customer accounted for greater than 10% of oil and gas revenues. In 2003 and 2004, sales to Shell Trading (US) Company totaled approximately $19.7 million and $35.7 million, respectively, and accounted for 21.5% and 26.4%, respectively, of the Company's oil and gas revenues exclusive of the impact of hedges. Also in 2004, sales to Conoco Phillips Company totaled approximately $16.2 million and accounted for 12.0% of the Company's oil and gas revenue exclusive of the impact of hedges. The Company uses the sales method of accounting for revenue. Under this method, oil and gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Gas imbalances are created, but not recorded, when the sales amount is not equal to the Company's entitled share of production. The Company's entitled share is calculated as the total or gross production of the property multiplied by the Company's decimal interest in the property. No provision is made unless the gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. Then a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. As of December 31, 2004, the Company had recorded a net liability of approximately $850,000, representing approximately 500,000 MCF at an average price of $1.70 per MCF, related to imbalances on properties at or nearing depletion. The net liability accrued as of December 31, 2003, was approximately $1.1 million for approximately 379,000 MCF at an average price of $2.95 per MCF. The gas imbalances were valued using the price at which the imbalance originated if there is a gas balancing agreement or the current price where there is no gas balancing agreement. Reserve reductions on any fields that have imbalances could cause this liability to increase. Settlements are typically negotiated, so the per MCF price for which imbalances are settled could differ among wells and even among owners in one well. Exclusive of the liability recorded for properties at or nearing depletion (see discussion above), the Company's remaining unrecorded imbalance, valued at current prices, would be approximately a $593,000 liability. RECEIVABLES The Company records receivables at their net realizable value with specific write off of receivables that are not deemed to be collectible. Joint interest billing receivables represent those amounts due to the Company as operator of an oil and gas property by the other working interest owners. Since these owners could also be the operator of other properties in which the Company is a working interest owner, the interdependency of the owners tends to assure timely payment. Balances that are past due for more than 90 days and over $30,000 are reviewed for collectibility quarterly, and are charged against earnings when the potential for collection is determined to be remote. The Company recognized such bad debt expense, included in interest and other income on the Consolidated Statement of Operations, of $441,000 and $185,000 related to such receivables for the years ended December 31, 2004 and 2002, respectively. In 2003 the Company made full or partial collection of several previously written off balances for a net gain 60 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of approximately $109,000. At December 31, 2004, two outstanding balances account for approximately 25% and 20% of the total receivable balance, respectively, and approximately 51% of that outstanding balance is less than 30 days old. No other customers account for more than 10% of the Company's outstanding receivables. The Company does not have any off-balance sheet credit exposure related to its customers. From time to time, certain other receivables are created and may be significant. At December 31, 2003, the Company had recorded a receivable of approximately $1.5 million from a private oil and gas company representing six months of override revenue. On November 8, 2004, the Company received $1.5 million as full payment of this receivable. At December 31, 2003, the Company had recorded a receivable of approximately $2.4 million from its insurance carrier, representing repair costs incurred as a direct result of hurricane Lili in 2002. In May 2004, the Company received $2.45 million from its insurance carrier as final settlement for this hurricane damage claim. CASH HELD FOR REINVESTMENT The approximately $24.9 million shown as cash held for reinvestment on the Consolidated Balance Sheet dated December 31, 2003 represents the net proceeds of the oil and gas property sales that were closed during the fourth quarter of 2003. The Company's credit facility requires that sale proceeds in excess of $5.0 million be reinvested in approved replacement oil and gas properties. The Company reinvested the sale proceeds by acquiring the Jalmat field in the Permian Basin on January 30, 2004. OTHER ASSETS The other assets line on the Consolidated Balance Sheet contains items such as deferred financing costs, refundable deposits and equity investments. As of December 31, 2004, $7.6 million, or 90% of the $8.4 million balance in other assets consisted of deferred financing costs. We amortize our deferred financing costs monthly, over the life of the underlying debt agreement, to interest and related expenses. For the year ended December 31, 2004 we amortized $1.7 million of our deferred financing costs. INCOME TAXES Deferred taxes are accounted for under the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The ultimate realization of deferred tax assets is dependent upon the recognition of future taxable income in periods when the temporary differences are available. The effect on deferred taxes of a change in tax rates is recognized in income in the period the change occurs. STATEMENT OF CASH FLOWS For cash flow presentation purposes, the Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Interest paid in cash for the years ended December 31, 2004, 2003 and 2002, was $17.7 million, $26.7 million, and $26.4 million, respectively. Net cash tax refunds of approximately $0.5 million and $1.8 million were received in the years ended December 31, 2003 and 2002, respectively. Cash taxes of $481,000 were paid in the year ended December 31, 2004. The Company issued 16.75 million shares of its common stock in exchange for $40 million of the 10 7/8% senior subordinated notes due 2007 in three separate non cash transactions in December 2003, February 2004 and March 2004. 61 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) BENEFIT PLANS During 1993, the Company adopted the Mission Resources Simplified Employee Pension Plan (the "Savings Plan") whereby all employees of the Company are eligible to participate. The Savings Plan is administered by a Plan Administrator appointed by the Company. Eligible employees may contribute a portion of their annual compensation up to the legal maximum established by the Internal Revenue Service for each plan year. The Company matches contributions up to a maximum of 6% each plan year. Employee contributions are immediately vested and employer contributions have a four-year vesting period. Amounts contributed by the Company to the Savings Plan for the years ended December 31, 2004, 2003 and 2002 were approximately $345,000, $335,000, and $96,000, respectively. DEFERRED COMPENSATION PLAN In late 1997, the Company adopted the Mission Deferred Compensation Plan. This plan allowed selected employees the option to defer a portion of their compensation until their retirement or termination. Such deferred compensation was invested in any one or more of six mutual funds managed by a fund manager at the direction of the employees. The market value of these investments was included in current assets at December 31, 2002 and was approximately $419,000. An equivalent liability due to the plan participants was included in current liabilities. In June 2003, the Company terminated the Mission Deferred Compensation Plan, and the fund manager made final distributions of all funds held in the plan to the plan participants. Both the current asset and the current liability of approximately $111,000 related to the plan at the termination date were removed from the Balance Sheet. STOCK-BASED EMPLOYEE COMPENSATION PLANS At December 31, 2004, the Company has two active stock-based employee compensation plans: the 1996 Stock Incentive Plan and the 2004 Stock Incentive Plan. The 2004 Plan was approved by the Board of Directors on March 4, 2004 and by the Company's stockholders at the May 19, 2004 annual stockholders' meeting. One inactive plan, the 1994 Stock Incentive Plan, still has options outstanding that have not expired or been exercised; however, no new options can be granted under the plan. The Company accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation cost is reflected in net income for options granted under those plans with an exercise price equal to the market value of the underlying common stock on the date of the grant. Net income would be affected; however, if the exercise price of the option differed from the market price. SFAS No. 148, Accounting for Stock-Based Compensation -- Transition and Disclosure, amends SFAS No. 123 to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and to require prominent disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. SFAS No. 148 amends APB Opinion No. 28, Interim Financial Reporting, to require disclosure about those effects in interim financial information. 62 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation and FASB Statement No. 148, Accounting for Stock-Based Compensation -- Transition and Disclosure to stock-based employee compensation (amounts in thousands, except per share amounts).
YEAR ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, DECEMBER 31, 2004 2003 2002 --------------- --------------- --------------- Net income (loss)* As reported................................... $2,949 $2,367 $(38,484) Pro forma..................................... $ (919) $ 729 $(39,315) Earnings (loss) per share As reported................................... $ 0.08 $ 0.10 $ (1.63) Pro forma..................................... $(0.02) $ 0.03 $ (1.67) Diluted earnings (loss) per share share As reported................................... $ 0.07 $ 0.10 $ (1.63) Pro forma..................................... $(0.02) $ 0.03 $ (1.67)
--------------- * The stock-based employee compensation cost, net of the related tax effects, that would have been included in the determination of net income if the fair value method had been applied to all awards is $3.9 million, $1.6 million and $0.8 million for the years ended December 31, 2004, 2003 and 2002, respectively. GOODWILL SFAS No. 142, Goodwill and Other Intangible Assets was approved in June 2001. This pronouncement requires that intangible assets with indefinite lives, including goodwill, cease being amortized and be evaluated on an annual basis for impairment. The Company adopted SFAS No. 142 on January 1, 2002 at which time the Company had unamortized goodwill, related to the Bargo merger, in the amount of $15.1 million and unamortized identifiable intangible assets in the amount of $374,300, all subject to the transition provisions. Upon adoption of SFAS No. 142, $277,000 of workforce intangible assets recorded as unamortized identifiable assets was subsumed into goodwill and was not amortized as it no longer qualified as a recognizable intangible asset. The transition and impairment test for goodwill, effective January 1, 2002, was performed in the second quarter of 2002. As of January 1, 2002, the Company's fair value exceeded the carrying amount; therefore, goodwill was not impaired. Mission designated December 31st as the date for its annual test. Based upon the results of such test at December 31, 2002, goodwill was fully impaired and a write-down of $16.7 million was recorded. 63 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The changes in the carrying amount of goodwill for the period ended December 31, 2002, are as follows (amounts in thousands):
INTANGIBLE TOTAL GOODWILL GOODWILL ASSETS AND INTANGIBLES -------- ---------- --------------- Balance, December 31, 2001......................... $ 15,061 $ 375 $ 15,436 Transferred to goodwill............................ 277 (277) -- Amortization of lease.............................. -- (98) (98) Merger purchase price allocation adjustments....... 1,341 -- 1,341 Goodwill impairment................................ (16,679) -- (16,679) -------- ----- -------- Balance, December 31, 2002......................... $ -- $ -- $ -- ======== ===== ========
COMPREHENSIVE INCOME Comprehensive income includes all changes in a company's equity except those resulting from investments by owners and distributions to owners. The accumulated balance of other comprehensive income related to cash flow hedges, net of taxes, is as follows (in thousands): Balance at January 1, 2002.................................. $ 2,286 Net gains (losses) on cash flow hedges...................... (341) Reclassification adjustments................................ (8,323) Tax effect on hedge activity................................ 2,183 -------- Balance at December 31, 2002................................ (4,195) Net gains (losses) on cash flow hedges...................... (15,755) Reclassification adjustments................................ 14,991 Tax effect on hedge activity................................ (748) -------- Balance at December 31, 2003................................ (5,707) Net gains (losses) on cash flow hedges...................... (20,656) Reclassification adjustments................................ 19,597 Tax effect on hedge activity................................ (1,167) -------- Balance at December 31, 2004................................ $ (7,933) ========
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Accounting for qualified hedges allows a derivative's gains and losses to offset related results on the hedged item in the Consolidated Statement of Operations. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Other Comprehensive Income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based upon the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings. 64 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ASSET RETIREMENT OBLIGATIONS In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which provided accounting requirements for retirement obligations associated with tangible long-lived assets. SFAS No. 143 requires that the Company record a liability for the fair value of its asset retirement obligation, primarily comprised of its plugging and abandonment liabilities, in the period in which it is incurred if a reasonable estimate of fair value can be made. The liability is accreted at the end of each period through charges to operating expense. The amount of the asset retirement cost is added to the carrying amount of the related asset and this additional carrying amount is depreciated over the life of the asset. The Company adopted the provisions of SFAS No. 143 with a calculation effective January 1, 2003. The Company's assets are primarily working interests in producing oil and gas properties and related support facilities. The life of these assets is generally determined by the estimation of the quantity of oil or gas reserves available for production and the amount of time such production should require. The cost of retiring such assets, the asset retirement obligation, is typically referred to as abandonment costs. The Company hired independent engineers to provide estimates of current abandonment costs on all its properties, applied valuation techniques appropriate under SFAS No. 143, and recorded a net initial asset retirement obligation of $44.3 million on its Consolidated Balance Sheet. An asset retirement cost of $14.4 million was simultaneously capitalized in the oil and gas properties section of the Consolidated Balance Sheet. The adoption of SFAS No. 143 was accounted for as a change in accounting principle. The following table shows the changes in the asset retirement obligation that have occurred since its implementation in 2003 (in thousands):
YEAR ENDED YEAR ENDED ASSET RETIREMENT OBLIGATION DECEMBER 31, 2004 DECEMBER 31, 2003 --------------------------- -------------------- -------------------- Beginning balance/Initial Implementation............ $33,317 $44,266 Liabilities incurred................................ 9,035 698 Liabilities settled................................. (2,028) (9,444) Liabilities sold.................................... (2,342) -- Changes in estimates................................ (1,306) (3,466) Accretion expense................................... 1,202 1,263 ------- ------- Ending balance...................................... 37,878 33,317 Less: current portion............................... (2,512) (1,160) ------- ------- Long-term portion................................... $35,366 32,157 ======= =======
NEW ACCOUNTING PRONOUNCEMENTS Staff Accounting Bulletin ("SAB") No. 106, regarding the application of FASB Statement No. 143, Accounting for Asset Retirement Obligations, by oil and gas producing companies following the full cost accounting method was issued in September 2004. SAB 106 provided an interpretation of how a company, after adopting Statement 143, should compute the full cost ceiling to avoid double-counting the expected future cash outflows associated with asset retirement costs. The provisions of this interpretation have been applied by the Company and has no impact on the financial statements. SFAS No. 123R, Share-Based Payments was issued in December 2004. SFAS No. 123R requires public companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period. SFAS No. 123R amends the original SFAS No. 123 and 95 that had allowed companies to choose between expensing stock options or showing pro forma disclosure only. 65 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) SFAS No. 123R becomes effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The impact of SFAS No. 123R is dependent upon grants issued and; therefore, cannot be estimated at this time. USE OF ESTIMATES Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as well as reserve information which affects the depletion calculation and the computation of the full cost ceiling limitation to prepare these financial statements in conformity with generally accepted accounting principles in the United States. Actual results could differ from these estimates. RECLASSIFICATIONS Certain reclassifications of prior period statements and disclosures have been made to conform to current reporting practices. 3. ACQUISITIONS AND INVESTMENTS During the last three fiscal years, the Company has completed or made the following significant acquisitions and investments: On January 30, 2004, the Company closed the $26.6 million acquisition of the Jalmat field in the Permian Basin of New Mexico. On April 13, 2004, the Company acquired an additional 14% working interest in the Jalmat field in Lea County, New Mexico for $3.6 million cash, before customary adjustments. These acquisitions added approximately 34.3 BCFE of proved reserves. After completion of this transaction the Company owns approximately a 94.5% operated working interest in the Jalmat field. On December 21, 2004, the Company acquired additional working interests in the Chocolate Bayou, Southwest Lake Boeuf, Backridge and West Lake Verret fields for approximately $11.0 million, before customary adjustments. The net reserves attributable to the interests being acquired are approximately 6 BCFE. The interests acquired approximately double the Company's current ownership in the fields and the Company is currently the operator of these fields. In 2003 spending for oil and gas property acquisitions was approximately $1.5 million. The most significant individual acquisition was that of an additional 13.6% interest in High Island 553 for approximately $621,000. The Company did not make any significant oil and gas property acquisitions during 2002. 4. RELATED PARTY TRANSACTIONS Mr. J. P. Bryan, a member of Mission's board of directors until October 2002, was Chairman and CEO of Mission from August 1999 through May 2000. Mr. Bryan is also Senior Managing Director of Torch Energy Advisors ("Torch") and owns shares representing 79.5% of the shares of Torch on a fully diluted basis. In 2002 and 2003, Torch performed services for Mission under various contracts. All 66 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) contracts with Torch were terminated effective April 1, 2003. The nature of services and amounts of the fees paid to Torch are summarized in the following table (amounts in thousands).
YEARS ENDED DECEMBER 31, ------------- 2003 2002 ---- ------ Oil and gas marketing(1).................................... $88 $ 343 Oil and gas property operations(1).......................... 75 1,400 Contract termination fee: oil and gas property operations... 75 --
--------------- (1) Mission formed its own operations and marketing teams which began performing these functions in early 2003. Mission currently uses an Oracle platform provided by P2 Energy Solutions under a July 2002 hosting agreement. Torch owns 21.2% of P2 Energy Solutions as the result of a January 15, 2003 merger of its Novistar subsidiary with Paradigm Technologies, a Petroleum Place company, that created P2 Energy Solutions. Mission paid hosting fees of $415,000, $667,000 and $373,000 in the years ended December 31, 2004, 2003 and 2002, respectively. In July 2002, Mission sold interests in several properties located in New Mexico to Chisos, LTD ("Chisos"). J.P. Bryan is the President and sole owner of Chisos. The $4.0 million bid from Chisos exceeded the highest of the three other bids by $250,000 and provided Mission a non-competition agreement in New Mexico, a one-year right to participate in developmental drilling and a one-year right to participate in any preferential rights events. These considerations were not offered to Mission by any other bidder. A $250,000 payment under a non-compete agreement was paid in the second quarter of 2002 to Tim J. Goff, Bargo's former Chief Executive Officer and former member of Mission's board of directors. In connection with the reorganization of the Mission's management team in 2002, the Company entered into separation agreements with each of Douglas G. Manner, Jonathan M. Clarkson, and Daniel P. Foley, on July 31, 2002, September 20, 2002, and November 15, 2002, respectively. Messrs. Manner, Clarkson and Foley were previously employed by the Company pursuant to employment agreements that provided for the payment of severance upon separation from the Company based on multiples of their current salary at the time of separation. The Company negotiated severance payments for each of Messrs. Manner, Clarkson and Foley that were considerably less than the amounts provided under their respective employment agreements. Under the terms of the separation agreements, the Company paid Messrs. Manner, Clarkson and Foley total payments of $1.3 million, $1.5 million and $450,000, respectively. Of the total $3.3 million, $250,000 was deferred and was amortized to expense over the term of the consulting contract and the remainder was charged to general and administrative expenses in 2002. Messrs. Manner, Clarkson and Foley also surrendered all of their options or rights to acquire the Company's securities. In addition, the Company agreed to provide Messrs. Manner and Clarkson with certain insurance benefits for up to 24 months after the separation date, and, to the extent the coverage or benefits received are taxable to either of Messrs. Manner or Clarkson, the Company agreed to make them "whole" on a net after-tax basis. Messrs. Manner and Clarkson also agreed to provide certain consulting services to the Company following their separation dates. In January 2003, Mr. Manner received a pay out in the sum of $314,852 from the Company's Deferred Compensation Plan made up primarily of deferred salary and bonuses under the terms of the plan Effective November 17, 2004, the Company entered into a Severance Agreement with Joseph G. Nicknish. Mr. Nicknish previously held the position of Senior Vice President, Operations and Engineering. Pursuant to an employment agreement with Mr. Nicknish, upon separation from the Company, the 67 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) employment agreement provided for the payment of a severance amount based on multiples of his current salary at the time of separation. Under the terms of the Severance Agreement, the Company agreed to pay Mr. Nicknish a severance amount of $500,000 payable in three equal installments commencing on December 30, 2004 and ending June 30, 2005. Under various programs, Mr. Nicknish had been granted 574,499 options to acquire the Company's common stock. Upon separation, these options were deemed exercisable for a period equal to the lesser of (i) one year following the separation date or (ii) the remaining term of the applicable option. In addition, the Company agreed to provide Mr. Nicknish with certain insurance benefits for up to 18 months after the separation date. 5. STOCKHOLDERS' EQUITY COMMON AND PREFERRED STOCK The Certificate of Incorporation of the Company initially authorized the issuance of up to 30,000,000 shares of common stock and 1,000,000 shares of preferred stock, the terms, preferences, rights and restrictions of which are established by the Board of Directors of the Company. In May 2001, the number of authorized shares was increased to 60 million shares of common stock and 5 million shares of preferred stock. On May 16, 2001, Bellwether merged with Bargo Energy Company ("Bargo"). The resulting company was renamed Mission Resources Corporation. As partial consideration in the merger, 9.5 million shares of Mission common stock were issued to the holders of Bargo common stock and options. The $80.0 million assigned value of such shares was included in the purchase price. On December 17, 2003, the Company entered into a purchase and sale agreement with FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income Series providing for the issuance of 4.5 million shares of the Company's common stock in exchange for the surrender by the Franklin entities of $10.0 million aggregate principal amount of the Company's 10 7/8% Notes due 2007. Accrued interest on the notes to the date of the agreement was paid on April 1, 2004, the regularly scheduled interest payment date for the notes, or upon the occurrence of certain other events On February 25, 2004, the Company acquired $15 million of its 10 7/8% Notes due 2007 from Stellar Funding, Ltd. in exchange for 6.25 million shares of the Company's common stock. On March 15, 2004, the Company acquired an additional $15 million of its 10 7/8% Notes due 2007 from Harbert Distressed Investment Master Fund, Ltd. in exchange for 6.0 million shares of the Company's common stock. On April 8, 2004, Mission issued 312,000 shares of its common stock in lieu of cash to its financial advisors as a fee for services rendered during the debt refinancing discussed below in Note 8. The $1.2 million fair value of this consideration was recorded as deferred financing costs in the other assets line of the Consolidated Balance Sheet. Certain restrictions contained in the Company's loan agreements limit the amount of dividends that may be declared. There is no present plan to pay cash dividends on common stock as the Company intends to reinvest its cash flows for continued growth of the Company. SHAREHOLDER RIGHTS PLAN In September 1997, the Company adopted a shareholder rights plan to protect Mission's shareholders from coercive or unfair takeover tactics. Under the shareholder rights plan, each outstanding share of Mission's common stock and each share of subsequently issued Mission common stock has attached to it one right. The rights become exercisable if a person or group acquires or announces an intention to acquire beneficial ownership of 15% or more of the outstanding shares of common stock without the prior consent of the Company. When the rights become exercisable each holder of a right will have the right to receive, 68 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) upon exercise of the right, a number of shares of common stock of the Company which, at the time the rights become exercisable, have a market price of two times the exercise price of the right. The Company may redeem the rights for $.01 per right at any time before they become exercisable without shareholder approval. The rights will expire on September 26, 2007, subject to earlier redemption by the board of directors of the Company. EARNINGS PER SHARE The following represents the reconciliation of the numerator (income) and denominator (shares) of the earnings per share computation to the numerator and denominator of the diluted earnings per share computation (amounts in thousands, except per share amounts):
YEAR ENDED DECEMBER 31, 2004 YEAR ENDED DECEMBER 31, 2003 ------------------------------ ------------------------------ INCOME SHARES PER SHARE INCOME SHARES PER SHARE ------- ------- ---------- ------- ------- ---------- Net income..................... $2,949 $2,367 ------ ------ Earnings per common share...... 2,949 38,529 $0.08 2,367 23,696 $0.10 Effect of dilutive securities: Options...................... -- 1,927 -- -- 1,041 -- ------ ------ ----- ------ ------ ----- Earnings per common share -- diluted...................... $2,949 40,456 $0.07 $2,367 24,737 $0.10 ====== ====== ===== ====== ====== =====
YEAR ENDED DECEMBER 31, 2002 ----------------------------- INCOME SHARES PER SHARE -------- ------ --------- Net income (loss)....................................... $(38,484) -------- ------ ------ Earnings (loss) per common share........................ (38,484) 23,586 $(1.63) Effect of dilutive securities: Options............................................... -- -- -- -------- ------ ------ Earnings (loss) per common share -- diluted............. $(38,484) 23,586 $(1.63) ======== ====== ======
Potentially dilutive options that are not in the money are excluded from the computation of diluted earnings per share because to do so would be antidilutive. For the years ended December 31, 2004, 2003 and 2002, the potentially dilutive options excluded represented 819,498, 1,171,500 and 1,050,500 shares, respectively. In periods of loss, the effect of potentially dilutive options that are in the money are excluded from the calculation of diluted earnings per share. For the year ended December 31, 2002, potential incremental shares of 250,000, were excluded. TREASURY STOCK In September 1998, the Company's Board of Directors authorized the repurchase of up to $5.0 million of the Company's common stock. As of December 31, 2002, 311,000 shares had been acquired at an aggregate price of $1.9 million. In the second quarter of 2003, the number of treasury shares increased to 389,323 because 78,323 shares were taken into treasury in lieu of collecting a note receivable valued at approximately $32,000. Treasury shares are valued at the price at which they are acquired, resulting in approximately $1.9 million being reported as a reduction to Stockholders' Equity as of December 31, 2003 and 2004. 69 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STOCK INCENTIVE PLANS The Company has stock option plans that provide for granting of options for the purchase of common stock to directors, officers and employees of the Company. These stock options may be granted subject to terms ranging from 6 to 10 years at a price equal to the fair market value of the stock at the date of grant. At December 31, 2004, there were 396,500 options available for grants. A summary of activity in the stock option plans is set forth below:
OPTION PRICE RANGE NUMBER OF -------------- SHARES LOW HIGH --------- ----- ------ Balance at December 31, 2001............................. 3,984,835 $3.34 $12.38 Granted................................................ 2,205,000 $0.31 $ 3.28 Surrendered(1)......................................... (2,974,335) $2.24 $12.38 ---------- Balance at December 31, 2002............................. 3,215,500 $0.31 $10.31 Granted................................................ 977,000 $0.38 $ 2.61 Surrendered............................................ (81,000) $5.75 $ 7.63 Exercised.............................................. (10,000) $0.38 $ 0.38 ---------- Balance at December 31, 2003............................. 4,101,500 $0.31 $10.31 Granted................................................ 2,474,500 $0.55 $ 6.23 Surrendered............................................ (51,999) $0.83 $10.00 Exercised.............................................. (837,035) $0.38 $ 4.72 ---------- Balance at December 31, 2004............................. 5,686,966 $0.31 $10.31 ========== Exercisable at December 31, 2002......................... 1,592,169 $0.31 $10.31 Exercisable at December 31, 2003......................... 2,793,168 $0.31 $10.31 Exercisable at December 31, 2004......................... 4,607,553 $0.31 $10.31
--------------- (1) In 2002, many employees voluntarily surrendered out of the money options. Detail of stock options outstanding and options exercisable at December 31, 2004 follows:
OUTSTANDING EXERCISABLE ------------------------------------------- -------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE REMAINING EXERCISE EXERCISE RANGE OF EXERCISE PRICES NUMBER LIFE (YEARS) PRICE NUMBER PRICE ------------------------ --------- ------------ ---------------- --------- -------- 1994 Plan $0.47 to $6.375.......... 438,668 7.3 $0.80 438,668 $0.80 1996 Plan $0.38 to $10.00.......... 2,858,799 7.5 $2.21 2,582,135 $2.31 2004 Plan $0.55 to $6.00........... 2,089,499 9.5 $2.98 1,486,750 $2.36 Non-Statutory Plan $6.23 to $6.23............................ 300,000 9.9 $6.23 100,000 $6.23 --------- --------- Total............................ 5,686,966 4,607,553 ========= =========
The estimated weighted average fair value per share of options granted during 2004, 2003, and 2002 was $7.64, $2.67, and $0.58, respectively. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. The Black-Scholes calculation was calculated as of year-end for 2002, but quarterly for 2003 and 2004 due to the quarterly reporting requirements of SFAS No. 148. 70 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following weighted-average assumptions were used for each calculation
STOCK PRICE AVERAGE EXPECTED PERIOD(1) VOLATILITY RISK FREE INTEREST RATE OPTION LIFE --------- ----------- ----------------------- ---------------- 2004 Quarter 2......................... 91% 4.8% 10 2004 Quarter 4......................... 56% 4.1% 10 2003 Quarter 1......................... 128% 3.9% 10 2003 Quarter 2......................... 168% 3.9% 10 2003 Quarter 3......................... 102% 4.2% 10 2003 Quarter 4......................... 86% 4.1% 10 2002 Full Year......................... 160% 3.9% 10
--------------- (1) There were no grants requiring Black-Scholes calculations in the first and third quarters of 2004. A tax benefit related to the exercise of employee stock options of approximately $1.2 million in 2004 was allocated directly to additional paid in capital. Such benefit was not material in 2003 and 2002. Concurrent with the 2001 Bargo merger, all Bellwether employees who held stock options were immediately vested in those options upon closing of the merger. Related to those options, an additional $102,000 of compensation expense was recognized in the year ended December 31, 2002, as a result of staff reductions. The expense was calculated as the excess of the stock price on the merger date over the exercise price of the option. On November 5, 2003, the Compensation Committee of the Board of Directors awarded Robert L. Cavnar, our Chairman of the Board, President and Chief Executive Officer, 800,000 share appreciation rights. The rights had an initial value of $0.55 for each right granted, had a term of ten years and fully vest only upon the occurrence of a "change of control" or the termination of Mr. Cavnar's employment by the Company without "cause" or by Mr. Cavnar for "good reason. On August 4, 2004, the Compensation Committee of the Board of Directors of the Company granted to Mr. Cavnar, a nonqualified option to acquire 800,000 shares of the Company's common stock. This option was granted to replace the grant of 800,000 share appreciation rights made to Mr. Cavnar in November 2003. The option was granted under the 2004 Incentive Plan, has a term of 10 years, is fully vested and has a strike price of $0.55 per share, which is the same exercise price as the surrendered share appreciation rights. As a result of this option having an exercise price below the market value for the Company's common stock at the time of issuance, the Company recognized a non-cash compensation expense of approximately $4.1 million ($2.6 million, net of tax) in the third quarter of 2004. 6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company produces and sells crude oil, natural gas and natural gas liquids. As a result, its operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. The Company periodically seeks to reduce its exposure to price volatility by hedging a portion of its production through swaps, options and other commodity derivative instruments. A combination of options, structured as a collar, is the Company's preferred hedge instrument because there are no up-front costs and protection is given against low prices. Such hedges assure that Mission receives NYMEX prices no lower than the price floor and no higher than the price ceiling. Hedging activities decreased revenues by $20.7 million, $15.8 million and $342,000 for the years 2004, 2003 and 2002, respectively. The Company's 12-month average realized price, excluding hedges, for natural gas was $0.12 per MCF less than the NYMEX MMBTU price. The Company's 12-month average realized price, excluding 71 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) hedges, for oil was $1.47 per BBL less than NYMEX. Realized prices differ from NYMEX as a result of factors such as the location of the property, the heating content of natural gas and the quality of oil. The gas differential stated above excludes the impact the Mist field gas production which is sold at an annually fixed price. In May 2002, several existing oil collars were cancelled. New swaps and collars hedging forecasted oil production were acquired. The Company paid approximately $3.3 million to counter parties, the fair value of the oil price collars at that time, in order to cancel the transactions. The cancellation of these hedges did not have an immediate impact on income. As required by SFAS No. 133, $418,000 related to the cancelled hedges had not yet been recognized in earnings. Such amount was amortized from other comprehensive income ("OCI") over the period of the hedged transactions and has been fully amortized at December 31, 2003 to the interest and other income line of the Statement of Operations. In October 2002, the Company elected to de-designate all existing hedges and to re-designate them by applying the interpretations from the FASB's Derivative Implementation Group issue G-20 ("DIG G-20"). The Company's previous approach to assessing ineffectiveness excluded time value which was recorded to income currently. By using the DIG G-20 approach, because the Company's collars and swaps meet specific criteria, the time value component is included in the hedge relationship and is recorded to OCI rather than income which reduces earnings variability. Both the realized and unrealized gains or losses related to these de-designated hedges at October 15, 2002 were amortized over the period of the hedged transactions. The Company's hedge program resulted in hedge ineffectiveness recognized in the interest and other income line of the Consolidated Statement of Operations of a net gain of $108,000 and $985,000 for the years ended December 31, 2004 and 2003, respectively, and a net loss of $9.1 million for the year ended December 31, 2002. As the existing hedges, listed in the tables below, settle over the next two years, gains or losses in OCI will be reclassified. The amount expected to be reclassified over the next twelve months will be a $6.8 million loss. The following tables detail the cash flow commodity hedges that were in place at December 31, 2004. OIL HEDGES
NYMEX NYMEX BBLS PRICE FLOOR PRICE CEILING PERIOD PER DAY TOTAL BBLS TYPE AVG. AVG. ------ ------- ----------- ------ ----------- ------------- First Qtr. 2005................ 2,500 225,000 Collar $28.71 $32.78 Second Qtr. 2005............... 2,000 182,000 Collar $28.50 $31.82 Third Qtr. 2005................ 2,000 184,000 Collar $28.13 $31.04 Fourth Qtr. 2005............... 2,000 184,000 Collar $27.75 $30.65 First Qtr. 2006................ 1,250 112,500 Collar $30.09 $46.48 Second Qtr. 2006............... 1,250 113,750 Collar $30.06 $45.13 Third Qtr. 2006................ 1,250 115,000 Collar $29.65 $44.36 Fourth Qtr. 2006............... 1,250 115,000 Collar $29.61 $43.41
72 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) GAS HEDGES
NYMEX NYMEX MMBTU PRICE FLOOR PRICE CEILING PERIOD PER DAY TOTAL MMBTU TYPE AVG. AVG. ------ ------- ----------- ------ ----------- ------------- First Qtr. 2005................ 15,500 1,395,000 Collar $5.00 $9.75 Second Qtr. 2005............... 11,500 1,046,500 Collar $4.91 $6.54 Third Qtr. 2005................ 11,500 1,058,000 Collar $4.91 $6.49 Fourth Qtr. 2005............... 11,500 1,058,000 Collar $4.91 $7.11 First Qtr. 2006................ 4,500 405,000 Collar $5.56 $9.25 Second Qtr. 2006............... 2,500 227,500 Collar $5.50 $7.13 Third Qtr. 2006................ 2,500 230,000 Collar $5.50 $7.15 Fourth Qtr. 2006............... 2,500 230,000 Collar $6.00 $7.08
The Company may also enter into financial instruments such as interest rate swaps to manage the impact of interest rates. Effective September 22, 1998, the Company entered into an eight and one-half year interest rate swap agreement with a notional value of $80.0 million. Under the agreement, Mission received a fixed interest rate and paid a floating interest rate. In February 2003, the interest rate swap was cancelled and the Company paid $1.3 million to the counter party. 7. DETERMINATION OF FAIR VALUES OF FINANCIAL INSTRUMENTS Fair value for cash, short-term investments, receivables and payables approximates carrying value. The commodity derivatives and the asset retirement obligations are also reflected on the Balance Sheet at fair value. The following table details the carrying values and approximate fair values of the Company's other investments and long-term debt at December 31, 2004 and 2003 (in thousands):
DECEMBER 31, 2004 DECEMBER 31, 2003 ---------------------------------- ---------------------- CARRYING APPROXIMATE CARRYING APPROXIMATE VALUE FAIR VALUE VALUE FAIR VALUE --------- ----------- -------- ----------- Assets (Liabilities): Long-term debt: (See Note 8) Term loan facility............................. $ -- $ -- $(80,000) $(80,000) Second lien term loan facility......... (25,000) (25,000) -- -- Senior secured revolving credit facility............................. (15,000) (15,000) -- -- 10 7/8% Notes, excluding unamortized premium.............................. -- -- (117,426) (110,968) 9 7/8% Notes........................... (130,000) (138,288) -- --
73 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. LONG-TERM DEBT Long-term debt is comprised of the following at December 31, 2004 and 2003 (in thousands):
DECEMBER 31, DECEMBER 31, 2004 2003 --------------- --------------- Term loan facility.......................................... $ -- $ 80,000 Second lien term loan facility.............................. 25,000 -- Senior secured revolving credit facility(1)................. 15,000 -- 10 7/8% Notes............................................... -- 117,426 Unamortized premium on 10 7/8% Notes........................ -- 1,070 9 7/8% Notes................................................ 130,000 -- -------- -------- Total debt.................................................. $170,000 $198,496 ======== ========
--------------- (1) $34.9 million was available at December, 31, 2004 for additional borrowings under this facility. Debt maturities by fiscal year are as follows (amounts in thousands): 2005........................................................ $ -- 2006........................................................ -- 2007........................................................ 15,000 2008........................................................ 25,000 2009........................................................ -- Thereafter.................................................. 130,000 -------- $170,000 --------
2004 REFINANCING On April 8, 2004, the Company issued $130 million of 9 7/8 Notes due 2011, announced the redemption of its 10 7/8% Notes due 2007 and replaced both its revolving credit facility and its term loan. Those transactions and the details of the resulting debt are discussed below. 9 7/8% NOTES On April 8, 2004, the Company issued $130.0 million of its 9 7/8% Notes due 2011 which are guaranteed on an unsubordinated, unsecured basis by all of its current subsidiaries. Interest on the notes is payable semi-annually, on each April 1 and October 1, commencing on October 1, 2004. A portion of the net proceeds from the offering of the 9 7/8% Notes was set aside to redeem, on May 10, 2004, the $87.4 million aggregate principal amount of the 10 7/8% Notes that remained outstanding. On April 8, 2004, the remainder of the net proceeds from the offering of the 9 7/8% Notes, together with $21.5 million that was advanced under the new senior secured revolving credit facility (as described below) and $25.0 million that was borrowed under the new second lien term loan (as described below), was used to completely discharge all of the Company's outstanding indebtedness under its prior revolving credit facility and term loan. At any time on or after April 9, 2005 and prior to April 9, 2008, the Company may redeem up to 35% of the aggregate original principal amount of the 9 7/8% Notes, using the net proceeds of equity offerings, at a redemption price equal to 109.875% of the principal amount of the 9 7/8% Notes, plus accrued and unpaid interest. On or after April 9, 2008, the Company may redeem all or a portion of the 74 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 9 7/8% Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest, if redeemed during the twelve-month period beginning on April 9 of the years indicated below:
YEAR PERCENTAGE ---- ---------- 2008........................................................ 104.93750% 2009........................................................ 102.46875% 2010........................................................ 100.00000%
If the Company experiences specific kinds of change of control, it may be required to purchase all or part of the 9 7/8% Notes at a price equal to 101% of the principal amount together with accrued and unpaid interest. The 9 7/8% Notes contain covenants that, subject to certain exceptions and qualifications, limit the Company's ability and the ability of certain of its subsidiaries to: - incur additional indebtedness or issue certain types of preferred stock or redeemable stock; - transfer or sell assets; - enter into sale and leaseback transactions; - pay dividends or make other distributions on stock, redeem stock or redeem subordinated debt; - enter into transactions with affiliates; - create liens on its assets; - guarantee other indebtedness; - enter into agreements that restrict dividends from subsidiaries; - make investments; - sell capital stock of subsidiaries; and - merge or consolidate. Standard and Poor's and Moody's currently publish debt ratings for the 9 7/8% Notes. Their ratings consider a number of items including the Company's debt levels, planned asset sales, near-term and long-term production growth opportunities, capital allocation challenges and commodity price levels. Standard & Poor's rating on the 9 7/8% Notes is "CCC" and Moody's rating is "Caa2." A decline in credit ratings will not create a default or other unfavorable change in the 9 7/8% Notes. SENIOR SECURED REVOLVING CREDIT FACILITY On April 8, 2004, the Company entered into a senior secured revolving credit facility led by Wells Fargo Bank, N.A. The facility, which matures on April 8, 2007, is secured by a first priority mortgage and security interest in at least 85% of the Company's oil and gas properties, all of the ownership interests of all of the Company's subsidiaries, and the Company's equipment, accounts receivable, inventory, contract rights, general intangibles and other assets. The facility is also guaranteed by all of the Company's subsidiaries. Availability under the facility, which includes a $3 million subfacility for standby letters of credit, is subject to a borrowing base that is determined at the sole discretion of the facility lenders. The initial borrowing base of the facility was $50 million, of which $30 million was available for general corporate purposes and $20 million was available for the acquisition of oil and gas properties approved by the 75 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) lenders. The borrowing base is redetermined on each April 1 and October 1. Mission and the lenders each have the option to request one unscheduled interim redetermination between scheduled redetermination dates. On October 1, 2004, it was determined that there would be no change in the borrowing base. On April 8, 2004, the Company was advanced $21.5 million under the facility, which amount, together with a portion of the net proceeds from the offering of the 9 7/8% Notes and $25 million that was borrowed under the new second lien term loan (as described below), was used to completely discharge all of the Company's outstanding indebtedness under its prior revolving credit facility and term loan. At December 31, 2004, $15.0 million in borrowings were outstanding and $34.9 million was available for borrowing ($20 million of which is restricted to the acquisition of oil and gas properties approved by the lenders). Advances under the facility bear interest, at the Company's option, at either (i) a margin (which varies from 25.0 basis points to 125.0 basis points based upon utilization of the borrowing base) over the base rate, which is the higher of (a) Wells Fargo's prime rate in effect on that day, and (b) the federal funds rate in effect on that day as announced by the Federal Reserve Bank of New York, plus 0.5%; or (ii) a margin (which varies from 175.0 basis points to 275.0 basis points based upon utilization of the borrowing base) over LIBOR. The Company is allowed to prepay any base rate or LIBOR loan without penalty, provided that each prepayment is at least $500,000 and multiples of $100,000 in excess thereof, plus accrued and unpaid interest. Standby letters of credit may be issued under the $3 million letter of credit subfacility. Mission is required to pay, to the issuer of the letter of credit, with respect to each issued letter of credit, (i) a per annum letter of credit fee equal to the LIBOR margin then in effect multiplied by the face amount of such letter of credit plus (ii) an issuing fee of the greater of $500 or 12.5 basis points. The facility requires the Company to hedge forward, on a rolling 12-month basis, at least 50% of proved producing volumes projected to be produced over the following 12 months. The Company is also required to hedge forward, on a rolling 12-month basis, at least 25% of proved producing volumes projected to be produced over the succeeding 12-month period. Any time that Mission has borrowings under the facility in excess of 70% of the borrowing base available for general corporate purposes, the agent under the facility may require Mission to hedge a percentage of projected production volumes on terms acceptable to the agent. The facility also contains the following restrictions on hedging arrangements and interest rate agreements: (i) the hedge provider must be a lender under the facility or an unsecured counterparty acceptable to the agent under the facility; and (ii) total notional volume must be not more than 75% of scheduled proved producing net production quantities in any period or, with respect to interest rate agreements, notional principal amount must not exceed 75% of outstanding loans, including future reductions in the borrowing base. The facility contains the following covenants which are considered important to Mission's operations. At December 31, 2004, the Company was in compliance with each of the following covenants: - Maintain a current ratio of consolidated current assets (as defined in the facility) to consolidated current liabilities (as defined in the facility) of not less than 1.0 to 1.0; - Maintain (on an annualized basis until the passing of four fiscal quarters and thereafter on a rolling four quarter basis) an interest coverage ratio (as defined in the facility) of no less than (i) 2.50 for June 30, 2004 through December 31, 2004, (ii) 2.75 for March 31, 2005 through June 30, 2005, and (iii) 3.0 for September 30, 2005 and thereafter; 76 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) - Maintain (on an annualized basis until the passing of four fiscal quarters and thereafter on a rolling four quarter basis) a leverage ratio (as defined in the facility) of no more than (i) 3.75 for June 30, 2004 through September 30, 2004, and (ii) 3.5 for December 31, 2004 and thereafter; and - Maintain a tangible net worth (as defined in the facility) of not less than 85% of tangible net worth at March 31, 2004, plus 50% of positive net income after tax distributions, plus 100% of equity offerings after March 31, 2004, excluding any asset impairment charges. The facility also includes restrictions with respect to changes in the nature of the Company's business; sale of all or a substantial or material part of its assets; mergers, acquisitions, reorganizations and recapitalizations; liens; guarantees; debt; leases; dividends and other distributions; investments; debt prepayments; sale-leasebacks; capital expenditures; lease expenditures; and transactions with affiliates. SECOND LIEN TERM LOAN On April 8, 2004, Mission entered into a second lien term loan with a syndicate of lenders arranged by Guggenheim Corporate Funding, LLC. The loan, which matures on April 8, 2008, is secured by a second priority security interest in the assets securing the senior secured revolving credit facility. The facility is also guaranteed by all of Mission's subsidiaries. On April 8, 2004, the Company borrowed the $25.0 million under the loan, which amount, together with a portion of the net proceeds from the offering of the 9 7/8% Notes and $21.5 million borrowed under the senior secured revolving credit facility (as described above), was used to completely discharge all of the outstanding indebtedness under the prior revolving credit facility and term loan. The loan accrues interest in each monthly interest period at the rate of 30-day LIBOR plus 525 basis points per annum, payable monthly in cash. The Company may prepay the loan at any time after the date six months and one day after April 8, 2004 in whole or in part in multiples of $1 million at the prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if prepaid during each successive 12-month period beginning on April 9th of each year indicated below:
YEAR PREMIUM ---- ------- 2004........................................................ 102% 2005........................................................ 101% 2006 to maturity............................................ 100%
Provided, however, that no prepayment shall be made prior to the date six months and one day after April 8, 2004. The loan contains covenants that are no more restrictive than those contained in the senior secured revolving credit facility. REDEEMED 10 7/8% NOTES In April 1997, the Company issued $100 million of 10 7/8% Notes due 2007. On May 29, 2001, the Company issued an additional $125 million of 10 7/8% Notes with identical terms to the notes issued in April 1997 at a premium of $1.9 million. The premium, shown separately on the Consolidated Balance Sheet, was amortized as a reduction of interest expense over the life of the 10 7/8% Notes so that the effective interest rate on the additional 10 7/8% Notes was 10.5%. Interest on the 10 7/8% Notes was payable semi-annually on April 1 and October 1. On March 28, 2003, the Company acquired, in a private transaction with various funds affiliated with Farallon Capital Management, LLC, approximately $97.6 million in principal amount of the 10 7/8% Notes for approximately $71.7 million, plus accrued interest. Including costs of the transaction and the removal 77 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of $2.2 million of previously deferred financing costs related to the acquired 10 7/8% Notes, the Company recognized a $22.4 million gain on the extinguishment of the 10 7/8% Notes. In December 2003, February 2004 and March 2004, the Company, in three private transactions, acquired $40.0 million aggregate principal amount of the 10 7/8% Notes in exchange for an aggregate of 16.75 million shares of its common stock as summarized below:
NET GAIN ON PRINCIPAL COMMON EXTINGUISHMENT DATE NOTE HOLDER VALUE SHARES OF 107/8 NOTES ---- ----------- ----------- ------------ -------------- December 2003............ FTVIPT -- Franklin Income $10 million 4.50 million $1.1 million Securities Fund and Franklin Custodian Funds -- Income Series February 2004............ Stellar Funding, Ltd. $15 million 6.25 million $0.5 million March 2004............... Harbert Distressed $15 million 6.00 million $0.9 million Investment Master Fund, Ltd.
On May 10, 2004, the remaining $87.4 million of 10 7/8% Notes were redeemed at a premium of approximately $1.6 million. This premium is included in the $4.1 million ($2.6 million, net of tax) net loss on extinguishment of debt reported in the three month period ended June 30, 2004. FORMER CREDIT FACILITIES The Company was party to a $150.0 million credit facility with a syndicate of lenders. The credit facility was a revolving facility, expiring May 16, 2004, which allowed Mission to borrow, repay and re-borrow under the facility from time to time. The total amount which might be borrowed under the facility was limited by the borrowing base periodically set by the lenders based on Mission's oil and gas reserves and other factors deemed relevant by the lenders. The facility was re-paid in full and cancelled on March 28, 2003. On March 28, 2003, simultaneously with the acquisition of $97.6 million in principal amount of the 10 7/8% Notes, the Company amended and restated the credit facility with new lenders, led by Farallon Energy Lending, LLC. Deferred financing costs of $947,000 relating to the previously existing facility were charged to earnings as a reduction in the gain on extinguishment of debt. Under the amended and restated facility, the Company borrowed $80.0 million, the proceeds of which were used to acquire approximately $97.6 million face amount of 10 7/8% Notes, to pay accrued interest on the 10 7/8% Notes purchased, and to pay closing costs. The amended and restated facility was cancelled in April 2004 and was replaced by the "Senior Secured Revolving Credit Facility" discussed above. 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, 2004 2003 2002 --------------- --------------- --------------- Current Federal................................. $ 145 $ 146 $ (734) State......................................... 152 130 -- Deferred Federal................................ 1,468 2,082 (10,846) State......................................... -- -- -- ------ ------ -------- Total income tax Expense (benefit).............. $1,765 $2,358 $(11,580) ====== ====== ========
78 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2004 and 2003 is as follows (in thousands):
DECEMBER 31, DECEMBER 31, 2004 2003 --------------- --------------- Federal tax net operating loss carryforwards................ $ 32,421 $ 31,958 Tax credits and other carryforwards......................... 1,053 433 Tax effect of hedging activities............................ 3,880 2,729 State tax net operating loss carryforwards.................. 2,770 2,901 Impairment of interest in Carpatsky......................... 2,186 2,186 Other....................................................... 2,501 1,044 -------- -------- Gross deferred tax asset.................................... 44,811 41,251 Less valuation allowance.................................... (3,874) (5,087) -------- -------- Deferred income tax asset................................... 40,937 36,164 Property, plant and equipment............................... (56,940) (53,434) Other....................................................... (356) -- -------- -------- Deferred income tax liability............................... (57,296) (53,434) ======== ======== Net deferred income tax asset (liability)................... $(16,359) $(17,270) ======== ========
In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the recognition of future taxable income during the periods in which those temporary differences are available. Based upon projections for future state taxable income, management believes it is more likely than not that the Company will not realize a portion of its deferred tax asset related to state tax net operating loss carryforwards. In addition, management believes it is more likely than not that the Company will not realize its deferred tax asset related to the impairment of the interest in Carpatsky. Accordingly, a valuation allowance has been recorded in the amount of $3.9 million and $5.1 million for the years ending December 31, 2004 and 2003, respectively. A tax benefit related to the cumulative effect of a change in accounting method of $0.9 million has been recorded and shown as part of the cumulative effect on the consolidated statements of operations in 2003. A tax benefit related to the exercise of employee stock options of approximately $1,206,000 was allocated directly to additional paid-in capital in 2004. Such benefit was not material in 2003 and 2002. 79 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Total income tax differs from the amount computed by applying the federal income tax rate to income before income taxes, minority interest, and cumulative adjustment. The reasons for the differences are as follows:
YEAR ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, DECEMBER 31, 2004 2003 2002 ------------ ------------ ------------ Statutory federal income tax rate............... 35.0% 35.0% 35.0% Increase (decrease) in tax rate resulting from: State income taxes, net of federal benefit.... 25.5% 5.0% 2.0% Change in state tax NOL valuation allowance... (23.0)% (3.7)% (2.0)% Non-deductible goodwill amort/impairment........ -- -- (11.7)% Other........................................... (0.1)% 0.2% (0.2)% ----- ---- ----- 37.4% 36.5% 23.1% ===== ==== =====
As previously described, on December 17, 2003, the Company issued 4.5 million shares of common stock in exchange for the surrender of $10 million of our 10 7/8% Notes due 2007. As a result of this transaction, management believes that the Company has experienced an "ownership change" as defined in Section 382 of the Internal Revenue Code, which could result in the imposition of significant limitations on the future use of the Company's existing net operating loss and tax credit carryforwards in the future. As of December 31, 2004, management believes that the limitations imposed by Section 382 will not result in the Company being unable to fully utilize its net operating loss and tax credit carryforwards to offset future taxable income and related tax liabilities. At December 31, 2004, the Company had federal regular tax net operating loss carryforwards of approximately $92.6 million, which will expire in future years beginning in 2009 and ending in 2022 as shown below.
(IN THOUSANDS) 2009........................................................ $ 804 2010........................................................ 96 2011........................................................ 878 Thereafter.................................................. 90,854 ------- Total..................................................... $92,632 =======
10. COMMITMENTS AND CONTINGENCIES LEASE COMMITMENTS The Company leases office space for the corporate office in downtown Houston, Texas. Small field offices are leased in Giddings, Texas, Eunice, New Mexico and Lafayette, Louisiana. At December 31, 2004, the minimum future payments under the terms of the Company's office space operating leases are as follows:
YEAR ENDED DECEMBER 31 ---------------------- ($ IN THOUSANDS) 2005........................................................ 658 2006........................................................ 658 2007........................................................ -- 2008........................................................ -- 2009........................................................ --
80 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Rent expense was approximately $721,000, $700,000, and $685,000 in 2004, 2003 and 2002, respectively. CONTINGENCIES The Company is involved in litigation relating to claims arising out of its operations in the normal course of business, including workmen's compensation claims, tort claims and contractual disputes. Some of the existing known claims against the Company are covered by insurance subject to limits of such policies and the payment of deductible amounts. Management believes that the ultimate disposition of uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on the Company's financial position, results of operations or cash flows. A dispute between the Minerals Management Service ("MMS") and the Company concerning the appropriate expenses to be used in calculating royalties was resolved in the third quarter of 2002. The Company agreed to pay the MMS approximately $170,000, which was less than the $1.9 million reserve previously classified as other liabilities on the Balance Sheet. The Company had reserved an amount each month assuming that the entire expense tariff being deducted could be disallowed by the MMS. The Company was able to resolve the dispute on more favorable terms, resulting in a $1.7 million gain that is included in interest and other income on the Consolidated Statement of Operations during the year ended December 31, 2002. In early 2002, Mission settled for $98,000 Garza Energy Trust, et al. v. Coastal Oil and Gas Corporation, et al. Mission had accrued $250,000 for the judgment in 2001, but later arrived at this more favorable settlement. The Company routinely obtains bonds to cover its obligations to plug and abandon oil and gas wells. In instances where the Company purchases or sells oil and gas properties, the parties to the transaction routinely include an agreement as to who will be responsible for plugging and abandoning any wells on the property and restoring the surface. In those cases, the Company will obtain new bonds or release old bonds regarding its plugging and abandonment exposure based on the terms of the purchase and sale agreement. However, if a party to the purchase and sale agreement defaults on its obligations to obtain a bond or otherwise plug and abandon a well or restore the surface or if that party becomes bankrupt, the landowner, and in some cases the state or federal regulatory authority, may assert that the Company is obligated to plug the well since it is in the "chain of title". The Company has been notified of such claims from landowners and the State of Louisiana and is vigorously asserting its rights under the applicable purchase and sale agreements to avoid this liability. As of December 31, 2004, the Company has accrued a liability for approximately $137,000 for the abandonment and cleanup of the Bayou Ferblanc field and a $370,000 liability for its proposal to settle on abandonment issues at the West Lake Ponchartrain field. 11. RESTRUCTURING In the latter half of 2002, Mission's Chief Executive Officer, Chief Financial Officer and Senior Vice President-Finance, left the Company to pursue other activities. This resulted in a charge of approximately $3.3 million, which is reflected in general and administrative expenses. As a condition to the separation agreements, the Company signed agreements with the former Chief Executive Officer and the former Chief Financial Officer to provide consulting services as needed over a 12-month period, the cost of which is amortized to expense over the period. 12. GUARANTEES In 1993 and 1996 the Company entered into agreements with surety companies and with Torch Energy Advisors Incorporated ("Torch") and Nuevo Energy Company ("Nuevo") whereby the surety 81 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) companies agreed to issue such bonds to the Company, Torch and/or Nuevo. However, Torch, Nuevo and the Company agreed to be jointly and severally liable to the surety company for any liabilities arising under any bonds issued to the Company, Torch and/or Nuevo. Torch currently has no bonds outstanding pursuant to these agreements and Nuevo has issued approximately $34.3 million of bonds. The Company has notified the sureties that it will not be responsible for any new bonds issued to Torch or Nuevo. However, the sureties are permitted under these agreements to seek reimbursement from the Company, as well and from Torch and Nuevo, if the surety makes any payments under the bonds issued to Torch and Nuevo. Effective May 17, 2004, Plains Exploration and Production Company acquired Nuevo Energy Company. The Company's subsidiaries, Mission E&P Limited Partnership, Mission Holdings LLC and Black Hawk Oil Company are guarantors under the Senior Secured Revolving Credit Facility, the Second Lien Term Loan and the indenture for the 9 7/8 Notes. 13. SUPPLEMENTAL GUARANTOR INFORMATION -- UNAUDITED Mission E&P Limited Partnership, Mission Holdings LLC and Black Hawk Oil Company, all subsidiaries of Mission Resources Corporation (collectively, the "Guarantor Subsidiaries") are guarantors under the senior secured revolving credit facility, the second lien term loan and the indenture for the 9 7/8% Notes. The Company does not believe that separate financial statements and other disclosures concerning the Guarantor Subsidiaries would provide any additional information that would be material to investors in making an investment decision. CONDENSED CONSOLIDATING BALANCE SHEETS -- UNAUDITED AS OF DECEMBER 31, 2004
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) Total current assets........................... $ 23,288 $ 5,498 $ -- $ 28,786 Net property, plant and equipment.............. 206,492 131,435 -- 337,927 Net leasehold, furniture and equipment......... 2,754 25 -- 2,779 Investment in subsidiaries..................... 149,260 143,970 (293,230) -- Total other assets............................. 8,411 -- -- 8,411 -------- -------- --------- -------- Total assets................................. $390,205 $280,928 $(293,230) $377,903 ======== ======== ========= ======== Total current liabilities...................... $ 35,772 $ 3,275 $ -- $ 39,047 Long-term debt................................. 170,000 -- -- 170,000 Deferred taxes................................. (45,341) 65,344 -- 20,003 Other long-term liabilities.................... 1,482 -- -- 1,482 Intercompany................................... 68,041 (68,041) -- -- Asset retirement obligation, excluding current portion...................................... 28,720 6,646 -- 35,366 Total stockholders' equity..................... 131,531 273,704 (293,230) 112,005 -------- -------- --------- -------- Total liabilities and stockholders' equity... $390,205 $280,928 $(293,230) $377,903 ======== ======== ========= ========
82 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING INCOME STATEMENTS -- UNAUDITED FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) Revenues........................................ $80,216 $45,424 $ -- $125,640 Equity in earnings from subsidiaries............ 3,163 -- (3,163) -- Expenses........................................ 86,843 34,083 -- 120,926 ------- ------- ------- -------- Net earnings (loss) before income taxes......... (3,464) 11,341 (3,163) 4,714 Income taxes.................................... (6,413) 8,178 -- 1,765 ------- ------- ------- -------- Net earnings (loss)............................. $ 2,949 $ 3,163 $(3,163) $ 2,949 ======= ======= ======= ========
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS -- UNAUDITED FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)........................... $ 2,949 $ 3,163 $(3,163) $ 2,949 Non-cash adjustments........................ 37,217 15,173 3,163 55,553 Changes in assets and liabilities........... (14,980) 15,156 -- 176 --------- -------- ------- --------- Net cash provided by operating activities... 25,186 33,492 -- 58,678 --------- -------- ------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Net property, plant and equipment........... (40,434) (33,444) -- (73,878) Leasehold, furniture and equipment.......... (1,159) (46) -- (1,205) Other....................................... 178 -- -- 178 --------- -------- ------- --------- Net cash used in investing activities....... (41,415) (33,490) -- (74,905) --------- -------- ------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings.................... 201,500 -- -- 201,500 Repayment borrowings........................ (200,511) -- -- (200,511) Stock issuance costs, net of proceeds....... 1,463 -- -- 1,463 Financing costs............................. (7,361) -- -- (7,361) Restricted cash held for investments........ 24,877 -- -- 24,877 --------- -------- ------- --------- Net cash provided by financing activities... 19,968 -- -- 19,968 Net increase (decrease) in cash and cash equivalents.............................. 3,739 2 -- 3,741 Cash and cash equivalents at beginning of period................................... 2,236 (2) -- 2,234 --------- -------- ------- --------- Cash and cash equivalents at end of period................................... $ 5,975 $ -- $ -- $ 5,975 ========= ======== ======= =========
83 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEETS -- UNAUDITED AS OF DECEMBER 31, 2003
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) Total current assets........................... $ 40,557 $ 6,897 -- $ 47,454 Net property, plant and equipment.............. 188,964 113,164 -- 302,128 Net leasehold, furniture and equipment......... 2,361 (21) -- 2,340 Investment in subsidiaries..................... 146,097 143,970 $(290,067) -- Total other assets............................. 5,404 -- -- 5,404 -------- -------- --------- -------- Total assets................................. $383,383 $264,010 $(290,067) $357,326 ======== ======== ========= ======== Total current liabilities...................... $ 30,185 $ 992 -- $ 31,177 Long-term debt................................. 198,496 -- -- 198,496 Deferred taxes................................. (37,034) 57,380 -- 20,346 Other long-term liabilities.................... 210 -- -- 210 Intercompany................................... 73,969 (73,969) -- -- Asset retirement obligation, excluding current portion...................................... 23,093 9,064 -- 32,157 Total stockholders' equity..................... 94,464 270,543 $(290,067) 74,940 -------- -------- --------- -------- Total liabilities and stockholders' equity... $383,383 $264,010 $(290,067) $357,326 ======== ======== ========= ========
CONDENSED CONSOLIDATING INCOME STATEMENTS -- UNAUDITED FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2003
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) Revenues........................................ $76,599 $47,375 $ -- $123,974 Equity in earnings from subsidiaries............ (2,363) -- 2,363 -- Expenses........................................ 69,265 48,248 -- 117,513 ------- ------- ------ -------- Net earnings (loss) before income taxes......... 4,971 (873) 2,363 6,461 Income taxes.................................... 1,402 956 -- 2,358 Cumulative effect of change in accounting method........................................ 1,202 534 -- 1,736 ------- ------- ------ -------- Net earnings (loss)............................. $ 2,367 $(2,363) $2,363 $ 2,367 ======= ======= ====== ========
84 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS -- UNAUDITED FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2003
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)............................ $ 2,367 $ (2,363) $ 2,363 $ 2,367 Non-cash adjustments......................... (3,357) 26,214 (2,363) 20,494 Changes in assets and liabilities............ 57,868 (61,840) -- (3,972) -------- -------- ------- -------- Net cash provided by operating activities.... 56,878 (37,989) -- 18,889 -------- -------- ------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Net property, plant and equipment............ (44,271) 37,898 -- (6,373) Leasehold, furniture and equipment........... (1,019) 89 -- (930) Other........................................ 850 -- -- 850 -------- -------- ------- -------- Net cash used in investing activities........ (44,440) 37,987 -- (6,453) -------- -------- ------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings..................... 80,000 -- -- 80,000 Repayment borrowings......................... (71,700) -- -- (71,700) Stock issuance costs, net of proceeds........ 4 -- -- 4 Financing costs.............................. (4,976) -- -- (4,976) Restricted cash held for investments......... (24,877) -- -- (24,877) -------- -------- ------- -------- Net cash provided by financing activities.... (21,549) -- -- (21,549) Net increase (decrease) in cash and cash equivalents............................... (9,111) (2) -- (9,113) Cash and cash equivalents at beginning of period.................................... 11,347 -- -- 11,347 -------- -------- ------- -------- Cash and cash equivalents at end of period... $ 2,236 $ (2) $ -- $ 2,234 ======== ======== ======= ========
CONDENSED CONSOLIDATING INCOME STATEMENTS -- UNAUDITED FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2002
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) Revenues....................................... $ 49,642 $ 55,822 $ -- $105,464 Equity in earnings from subsidiaries........... (13,868) -- 13,868 -- Expenses....................................... 87,354 68,174 -- 155,528 -------- -------- ------- -------- Net earnings (loss) before income taxes........ (51,580) (12,352) 13,868 (50,064) Income taxes................................... (13,096) 1,516 -- (11,580) -------- -------- ------- -------- Net earnings (loss)............................ $(38,484) $(13,868) $13,868 $(38,484) ======== ======== ======= ========
85 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS -- UNAUDITED FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2002
MISSION GUARANTOR RESOURCES SUBSIDIARIES ELIMINATIONS CONSOLIDATED --------- ------------ ------------ ------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)............................ $(38,484) $(13,868) $ 13,868 $(38,484) Non-cash adjustments......................... 53,573 19,670 (13,868) 59,375 Changes in assets and liabilities............ 23,626 (37,295) -- (13,669) -------- -------- -------- -------- Net cash provided by operating activities.... 38,715 (31,493) -- 7,222 -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Net property, plant and equipment............ 7,497 31,460 -- 38,957 Leasehold, furniture and equipment........... (231) 33 -- (198) Other........................................ -- -- -- -- -------- -------- -------- -------- Net cash used in investing activities........ 7,266 31,493 -- 38,759 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings..................... 21,000 -- -- 21,000 Repayment borrowings......................... (56,000) -- -- (56,000) Stock issuance costs, net of proceeds........ -- -- -- -- Financing costs.............................. (237) -- -- (237) Restricted cash held for investments......... -- -- -- -- -------- -------- -------- -------- Net cash provided by financing activities.... (35,237) -- -- (35,237) Net increase (decrease) in cash and cash equivalents............................... 10,744 -- -- 10,744 Cash and cash equivalents at beginning of period.................................... 603 -- -- 603 -------- -------- -------- -------- Cash and cash equivalents at end of period... $ 11,347 $ -- $ -- $ 11,347 ======== ======== ======== ========
14. SELECTED QUARTERLY FINANCIAL DATA (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED):
QUARTER ENDED --------------------------------------------------------------- DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31, 2004 2004 2004 2004 --------------- ---------------- ----------- ------------ Revenues................................ $34,026 $35,028 $27,175 $29,411 Operating income (loss)................. $ 4,526 $ 1,365 $(1,743) $ 566 Net income (loss)....................... $ 2,827 $ 868 $(1,106) $ 360 Income (loss) per common share.......... $ 0.07 $ 0.02 $ (0.03) $ 0.01 Income (loss) per common share -- diluted...................... $ 0.06 $ 0.02 $ (0.03) $ 0.01
86 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
QUARTER ENDED --------------------------------------------------------------- DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31, 2003 2003 2003 2003 --------------- ---------------- ----------- ------------ Revenues................................ $26,461 $24,241 $24,625 $48,647 Operating income (loss)................. $(2,174) $(5,841) $(4,532) $19,008 Net income (loss)....................... $(1,503) $(3,803) $(2,946) $10,619 Income (loss) per common share.......... $ (0.06) $ (0.16) $ (0.13) $ 0.45 Income (loss) per common share -- diluted...................... $ (0.06) $ (0.16) $ (0.13) $ 0.45
The loss in the second quarter of 2004 was attributable to a $2.6 million expense ($1.7 million, net of taxes) from the extinguishment of debt. The income in the first quarter of 2003 includes the $22.4 million gain on the extinguishment of debt related to the purchase and retirement of $97.6 million principal amount 10 7/8% senior subordinated notes due 2007. 15. SUPPLEMENTAL INFORMATION -- (UNAUDITED) OIL AND GAS PRODUCING ACTIVITIES: Included herein is information with respect to oil and gas acquisition, exploration, development and production activities, which is based on estimates of year-end oil and gas reserve quantities and estimates of future development costs and production schedules. Reserve quantities and future production are based primarily upon reserve reports prepared by the independent petroleum engineering firms. The reserve report for the years ended December 31, 2004, 2003 and 2002 were prepared by Netherland Sewell & Associates, Inc. Estimates of future net cash flows from proved reserves of gas, oil, condensate and natural gas liquids were made in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." The estimates are based on prices at year-end. Estimated future cash inflows are reduced by estimated future development costs (including future abandonment and dismantlement), and production costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Tax expense is calculated by applying the existing statutory tax rates, including any known future changes, to the pre-tax net cash flows, less depreciation of the tax basis of the properties and depletion allowances applicable to the gas, oil, condensate and NGL production. The impact of the net operating loss is considered in calculation of tax expense. The results of these disclosures should not be construed to represent the fair market value of the Company's oil and gas properties. A market value determination would include many additional factors including: 1) anticipated future increases or decreases in oil and gas prices and production and development costs; 2) an allowance for return on investment; 3) the value of additional reserves not considered proved at the present, which may be recovered as a result of further exploration and development activities; and 4) other business risks. 87 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) COSTS INCURRED (IN THOUSANDS):
YEAR ENDED DECEMBER 31, ---------------------------- 2004 2003 2002 -------- ------- ------- Property acquisition: Proved properties.................................... $ 38,553 $ 1,570 $ 850 Unproved properties.................................. 2,935 1,269 -- Exploration............................................ 8,633 4,311 1,337 Asset retirement....................................... 18,034 10,987 -- Development: Proved developed properties.......................... 24,536 13,832 16,377 Proved undeveloped properties........................ 12,251 13,481 2,876 -------- ------- ------- $104,942 $45,450 $21,440 ======== ======= =======
CAPITALIZED COSTS (IN THOUSANDS):
YEAR ENDED DECEMBER 31, ----------------------- 2004 2003 ---------- ---------- Proved properties........................................... $ 882,289 $ 799,777 Unproved properties......................................... 8,858 6,123 Asset retirement cost....................................... 18,034 10,987 --------- --------- Total capitalized costs..................................... 909,181 816,887 Accumulated depreciation, depletion, amortization and impairment................................................ (571,254) (514,759) --------- --------- Net capitalized costs....................................... $ 337,927 $ 302,128 --------- ---------
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (IN THOUSANDS):
YEAR ENDED DECEMBER 31, ------------------ 2004 2003 -------- ------- Revenues from oil and gas producing activities.............. $128,707 $99,357 Production costs............................................ 38,029 40,515 Transportation costs........................................ 346 349 Asset retirement accretion expense.......................... 1,202 1,263 Income tax.................................................. 16,793 6,555 Depreciation, depletion and amortization.................... 44,229 38,501 -------- ------- Results of operations from producing activities (excluding corporate overhead and interest costs).................... $ 28,108 $12,174 ======== =======
88 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) PROVED AND PROVED DEVELOPED RESERVES The Company's estimated total proved and proved developed reserves of oil and gas are as follows:
YEAR ENDED DECEMBER 31, 2004 ------------------------- OIL NGL GAS (MBBL) (MBBL) (MMCF) ------ ------ ------- Proved reserves at beginning of year.................... 13,724 1,734 85,106 Revisions of previous estimates......................... 1,154 313 (8,703) Extensions and discoveries.............................. 1,252 2,326 14,624 Production.............................................. (1,647) (308) (12,367) Sales of reserves in-place.............................. (412) -- (1,441) Purchase of reserves in-place........................... 903 3,116 15,905 ------ ----- ------- Proved reserves at end of year.......................... 14,974 7,181 93,124 ====== ===== ======= Proved developed reserves -- Beginning of year..................................... 11,502 1,642 54,204 ====== ===== ======= End of year........................................... 13,053 5,117 68,510 ====== ===== =======
YEAR ENDED DECEMBER 31, 2003 ------------------------ OIL NGL GAS (MBBL) (MBBL) (MMCF) ------ ------ ------ Proved reserves at beginning of year.................... 22,605 2,004 81,491 Revisions of previous estimates......................... 10 (193) 4,642 Extensions and discoveries.............................. 1,310 47 14,819 Production.............................................. (2,098) (107) (9,675) Sales of reserves in-place.............................. (8,103) (17) (6,692) Purchase of reserves in-place........................... -- -- 521 ------ ----- ------ Proved reserves at end of year.......................... 13,724 1,734 85,106 ====== ===== ====== Proved developed reserves -- Beginning of year..................................... 18,581 1,869 53,708 ====== ===== ====== End of year........................................... 11,502 1,642 54,204 ====== ===== ======
89 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31, 2002 -------------------------- OIL NGL GAS (MBBL) (MBBL) (MMCF) ------- ------ ------- Proved reserves at beginning of year.................... 39,538 2,060 154,082 Revisions of previous estimates......................... (1,915) 251 (42,426) Extensions and discoveries.............................. 227 -- 537 Production.............................................. (3,157) (266) (12,524) Sales of reserves in-place.............................. (12,093) (41) (18,178) Purchase of reserves in-place........................... 5 -- -- ------- ----- ------- Proved reserves at end of year.......................... 22,605 2,004 81,491 ======= ===== ======= Proved developed reserves -- Beginning of year..................................... 31,902 1,924 97,984 ======= ===== ======= End of year........................................... 18,581 1,869 53,708 ======= ===== =======
DISCOUNTED FUTURE NET CASH FLOWS The standardized measure of discounted future net cash flows and changes therein related to proved oil and gas reserves are shown below (in thousands):
YEAR ENDED YEAR ENDED YEAR ENDED DECEMBER 31, 2004 DECEMBER 31, 2003 DECEMBER 31, 2002 -------------------- -------------------- -------------------- Future cash flow.................... $1,407,517 $ 978,315 $1,075,050 Future production costs............. (492,122) (315,850) (405,251) Future income taxes................. (200,100) (135,803) (125,094) Future development costs............ (120,161) (74,090) (74,034) ---------- --------- ---------- Future net cash flows............... 595,134 452,572 470,671 10% discount factor................. (274,325) (177,984) (214,843) ---------- --------- ---------- Standardized future net cash flows............................. $ 320,809 $ 274,588 $ 255,828 ========== ========= ==========
90 MISSION RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):
YEAR ENDED YEAR ENDED YEAR ENDED DECEMBER 31, 2004 DECEMBER 31, 2003 DECEMBER 31, 2002 -------------------- -------------------- -------------------- Standardized measure -- beginning of year.............................. $ 274,588 $255,828 $295,571 Sales, net of production costs...... (110,971) (74,249) (60,031) Net change in prices and production costs............................. 51,453 36,042 160,132 Net change in income taxes.......... (27,726) (4,795) (2,635) Extensions, discoveries and improved recovery, net of future production and development costs............. 59,020 74,697 3,803 Changes in estimated future development costs................. (21,653) (16,740) 4,459 Development costs incurred during the period........................ 31,424 24,283 15,870 Revisions of quantity estimates..... 256 6,243 (78,419) Accretion of discount............... 27,459 25,583 29,557 Asset retirement.................... 2,026 3,550 -- Purchases of reserves in place...... 63,286 343 84 Sales of reserves in-place.......... (5,286) (69,502) (56,875) Changes in production rates and other............................. (23,067) 13,305 (55,688) --------- -------- -------- Standardized measure -- end of year.............................. $ 320,809 $274,588 $255,828 ========= ======== ========
The discounted future cash flows above were calculated using the NYMEX WTI Cushing price for oil and the NYMEX Henry Hub price for gas that was posted for the last trading day of each year presented. Those prices were $43.33, $32.47 and $31.17 per barrel and $6.18, $5.97 and $4.74 per MMBTU, for December 31, 2004, 2003 and 2002, respectively, adjusted to the wellhead to reflect adjustments for transportation, quality and heating content. The foregoing discounted future net cash flows do not include the effects of hedging or other derivative contracts not specific to a property. Including the tax effected impact of hedging on discounted future net cash flow would have decreased discounted future net cash flows by approximately $6.9 million, $6.4 million and $7.7 million as of December 31, 2004, 2003 and 2002, respectively. 91 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As of the end of the period covered by this report, Mission's principal executive officer ("CEO") and principal financial officer ("CFO") carried out an evaluation of the effectiveness of Mission's disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934. Based on those evaluations, the CEO and CFO believe: (i) that Mission's disclosure controls and procedures are designed to ensure that information required to be disclosed by Mission in the reports it files under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Mission's management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and (ii) that Mission's disclosure controls and procedures are effective. MANAGEMENT, REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING Management's Report on Internal Controls over Financial Reporting which appears on page 54, is incorporated herein by reference. CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING There have been no significant changes in Mission's internal controls over financial reporting during the period covered by this report that has materially affected, or are reasonably likely to materially affect, Mission's control over financial reporting. ITEM 9B. OTHER INFORMATION None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference. 92 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2004. Such information is incorporated herein by reference. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) 1. and 2. Financial Statements and Financial Statement Schedules. See index to Consolidated Financial Statements and Supplemental Information in Item 8, which information is incorporated herein by reference. 3. Exhibits. 2.1 Agreement and Plan of Merger dated January 24, 2001 between the Company and Bargo Energy Company (incorporated by reference to Exhibit 2.1 to the Company's 8-K filed on January 26, 2001). 3.1 Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement No. 33-76570 filed on March 17, 1994). 3.2 Certificate of Amendment to Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K filed on September 27, 1997). 3.3 Certificate of Designation, Preferences and Rights of the Series A Preferred Stock of the Company (incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K filed on September 27, 1997). 3.4 Certificate of Merger of Bargo Energy Company into the Company (incorporated by reference to Exhibit 3.4 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 3.5 Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.5 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 3.6 By-laws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement No. 33-76570 filed on March 17, 1994). 3.7 Amendment to the Company's Bylaws adopted on November 21, 1997 (incorporated by reference to Exhibit 3.5 to the Company's Annual Report on Form 10-K filed on March 27, 1998). 3.8 Amendment to the Company's Bylaws adopted on March 27, 1998 (incorporated by reference to Exhibit 3.6 to the Company's Annual Report on Form 10-K filed on March 27, 1998). 4.1 Specimen Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 4.2 Rights Agreement between the Company and American Stock Transfer & Trust Company (incorporated herein by reference to Exhibit 1 to the Company's Registration Statement on Form 8-A filed on September 19, 1997). 4.3 Amendment to Rights Agreement dated as of December 17, 2003, by and between Mission Resources Corporation and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on December 18, 2003). 4.4 Amendment to Rights Agreement dated as of February 25, 2004, by and between the Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on February 26, 2004).
93 4.5 Amendment to Rights Agreement dated as of March 15, 2004 by and between the Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on March 16, 2004). 4.6 Indenture dated as of May 29, 2001 among the Company, the Subsidiary Guarantors named therein and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-4 filed on July 27, 2001). 4.7 Registration Rights Agreement dated December 17, 2003, by and among the Company and FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income Series (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on December 18, 2003). 4.8 Registration Rights Agreement dated February 25, 2004, by and among the Company and Stellar Funding Ltd. (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on February 26, 2004). 4.9 Registration Rights Agreement dated March 15, 2004, by and between the Company and Harbert Distressed Investment Master Fund, Ltd. (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on March 16, 2004). 4.10 Indenture dated as of April 8, 2004, among the Company, the Guarantors named therein and The Bank of New York, as Trustee, relating to the Company's 9 7/8% Senior Notes due 2011 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K/A filed on April 15, 2004). 10.1+ 1994 Stock Incentive Plan (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement No. 33-76570 filed on March 17, 1994). 10.2+ 1996 Stock Incentive Plan (incorporated by reference to Exhibit A to the Company's Proxy Statement on Schedule 14A filed on October 21, 1996). 10.3+ 2004 Incentive Plan (incorporated by reference to Appendix C to the Company's Proxy Statement on Schedule 14A filed on March 30, 2004). 10.4 Amended and Restated Credit Agreement, dated as of March 28, 2003, among the Company, Farallon Energy Funding, LLC, as Arranger and Lender, Jefferies & Company, Inc., as Syndication Agent and Foothill Capital Corporation, as Administrative Agent (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, filed April 1, 2003). 10.5 Second Amended, Restated and Consolidated Guaranty and Collateral Agreement, dated as of march 28, 2003, made by the Company and certain of its Subsidiaries, in favor of Foothill Capital Corporation, as Administrative Agent (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K, filed April 1, 2003). 10.6 Second Amended and Restated Credit Agreement among the Company, as Borrower, the Several Lenders from Time to Time Parties Hereto, Farallon Energy Lending, L.L.C., as Arranger Jefferies & Company, Inc., as Syndication Agent and Wells Fargo Foothill, Inc., as Administrative Agent dated as of June 5, 2003 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K filed on June 17, 2003). 10.7 Third Amended, Restated And Consolidated Guaranty And Collateral Agreement, dated as of June 5, 2003, made by the Company and certain of its Subsidiaries, in favor of Wells Fargo Foothill, Inc., as Administrative Agent (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K filed on June 17, 2003). 10.8 First Amendment to and Waiver of Second Amended and Restated Credit Agreement, dated as of June 25, 2003, among the Company, the several banks and other financial institutions or entities from time to time parties to the Amendment, Farallon Energy Lending, L.L.C., as sole advisor, sole lead arranger and sole bookrunner, and Wells Fargo Foothill, Inc, as administrative agent (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed November 13, 2003).
94 10.9 Second Amendment, dated October 22, 2003, to the Second Amended and Restated Credit Agreement, dated as of June 5, 2003, by and among the Company, the several banks and other financial institutions or entities from time to time parties thereto, Farallon Energy Lending, L.L.C., as sole advisor, sole lead arranger and sole bookrunner, Jefferies & Company, Inc., as the syndication agent, and Wells Fargo Foothill, Inc, formerly known as Foothill Capital Corporation, as administrative agent (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed November 13, 2003). 10.10 Credit Agreement dated as of April 8, 2004, among the Company, as Borrower, Wells Fargo Bank, National Association, as Lead Arranger and Administrative Agent, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K/ A filed on April 15, 2004). 10.11 Term Loan Agreement dated as of April 8, 2004, among the Company, as Borrower, Guggenheim Corporate Funding, LLC, as Collateral Agent, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K/A filed on April 15, 2004). 10.12 Intercreditor Agreement dated as of April 8, 2004, by and between the Company, the Company's Subsidiaries, Wells Fargo Bank, National Association and Guggenheim Corporate Funding LLC (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K/A filed on April 15, 2004). 10.13 Purchase and Sale Agreement, dated as of March 28, 2003, by and between Farallon Capital Management, LLC and the Company, as Administrative Agent (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K, filed April 1, 2003). 10.14 Purchase and Sale Agreement, dated as of December 17, 2003, by and among the Company and FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income Series (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on December 18, 2003). 10.15 Purchase and Sale Agreement, dated as of February 25, 2004, by and between the Company and Stellar Funding Ltd. (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on February 26, 2004). 10.16 Purchase and Sale Agreement, dated as of March 15, 2004, by and between the Company and Harbert Distressed Investment Master Fund, Ltd. (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on March 16, 2004). 10.17+ Employment Agreement dated August 8, 2002, between the Company and Robert L. Cavnar (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed November 14, 2002). 10.18+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Robert L. Cavnar (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.19+ Employment Agreement dated October 8, 2002, between the Company and Richard W. Piacenti (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed November 14, 2002). 10.20+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Richard W. Piacenti (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.21+ Employment Agreement dated November 7, 2002, between the Company and John L. Eells (incorporated by reference to Exhibit 10.14 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 10.22+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and John L. Eells (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.23+ Employment Agreement dated November 6, 2002, between the Company and Joseph G. Nicknish (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K filed on March 31, 2003).
95 10.24+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Joseph G. Nicknish (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.25+ Severance Agreement dated November 17, 2004, between the Company and Joseph G. Nicknish (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 23, 2004). 10.26+ Employment Agreement effective November 4, 2003 between the Company and Marshall L. Munsell (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed on November 13, 2003). 10.27+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Marshall L. Munsell (incorporated by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.28*+ Employment Agreement dated as of November 1, 2004, between the Company and Thomas C. Langford. 10.29+ Non-statutory Stock Option Agreement dated as of November 1, 2004, between the Company and Thomas C. Langford (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 2, 2004). 10.30+ Form of Indemnification Agreement between the Company and each of its directors and executive officers (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed November 14, 2002). 10.31+ Form of Nonstatutory Stock Option Grant Agreement under the Company's 2004 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.32+ Form of Director Non-Qualified Stock Option (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.33+ Form of Incentive Stock Option Grant Agreement under the Company's 2004 Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.34*+ First Amendment to the Employment Agreement dated as of November 1, 2004, between the Company and Thomas C. Langford. 21.1* Subsidiaries of the Company. 23.1* Consent of KPMG LLP. 23.2* Consent of Netherland Sewell & Associates, Inc. 31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended. 31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended. 32.1* Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive Officer of the Company. 32.2* Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial Officer of the Company. --------------- * Filed herewith. + Management contract or compensatory plan or arrangement (b) Exhibits. See item 15(a)(3) above. (c) Financial Statement Schedules None. 96 GLOSSARY OF OIL AND GAS TERMS TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS - BBL -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons. - BCF -- One billion cubic feet of natural gas. - BCFE -- One billion cubic feet of natural gas equivalent, converting oil to gas at the ratio of 1 BBL of oil to 6 MCF of gas. - BOE -- One barrel of oil equivalent, converting gas to oil at the ratio of 6 MCF of gas to 1 BBL of oil. - BTU -- British thermal unit, a measurement of the energy content of natural gas. - MBBL -- One thousand Bbls. - MCF -- One thousand cubic feet of natural gas. - MCFE -- One thousand cubic feet of natural gas equivalent, converting oil to gas at a ratio of 1 BBL of oil to 6 MCF of gas. - MMCF -- One million cubic feet of natural gas. - MMBTU -- One million British thermal units. - MBOE -- One thousand BOE. - MMBOE -- One million BOE. - MMBBL -- One million BBLs. - NGLs -- Natural gas liquids. - TCF -- One trillion cubic feet of natural gas. TERMS USED TO DESCRIBE THE COMPANY'S INTERESTS IN WELLS AND ACREAGE - Gross oil and gas wells or acres -- Gross wells or gross acres represent the total number of wells or acres in which Mission owns a working interest. - Net oil and gas wells or acres -- Determined by multiplying "gross" wells or acres by the working interest that Mission owns in such wells or acres represented by the underlying properties. TERMS USED TO ASSIGN A PRESENT VALUE TO THE COMPANY'S RESERVES - Standard measure of proved reserves -- The present value, discounted at 10%, of the after-tax future net cash flows attributable to estimated net proved reserves. We calculate this amount by assuming that we will sell the oil and gas production attributable to the proved reserves estimated in the independent engineer's reserve report for the prices we received for the production on the date of the report, unless we had a contract to sell the production for a different price. We also assume that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes using rates in effect on the date of the report are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of our proved reserves. - Discounted present value -- The discounted present value of proved reserves is identical to the standardized measure, except that estimated future income taxes are not deducted in calculating future net cash flows. We disclose the discounted present value without deducting estimated income 97 taxes to provide what we believe is a better basis for comparison of our reserves to other producers who may have different tax rates. TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES - Proved reserves -- The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. The SEC definition of proved oil and gas reserves, per Article 4-10(a) (2) of Regulation S-X, is as follows: Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (b) Reserves which can be produced economically through application of improved recovery, techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. - Proved developed reserves -- Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. - Proved undeveloped reserves -- Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. TERMS THAT DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES - Average Reserve to Production Ratio in Years -- A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve life for the years ended December 31, 2004, 2003 or 2002 equals the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated. TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF OUR OIL AND GAS PROPERTIES - Royalty interest -- A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the 98 interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land. - Working interest -- A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property. TERMS USED TO DESCRIBE SEISMIC OPERATIONS - Seismic data -- Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geo-phones that digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations. - 2-D seismic data -- 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. - 3-D seismic -- 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated. MISCELLANEOUS DEFINITIONS - Infill drilling -- Infill drilling is the drilling of an additional well or additional wells in excess of those provided for by a spacing order in order to more adequately drain a reservoir. - Upstream oil and gas properties -- Upstream is a term used in describing operations performed before those at a point of reference. Production is an upstream operation and marketing is a downstream operation when the refinery is used as a point of reference. On a gas pipeline, gathering activities are considered to have ended when gas reaches a central point for delivery into a single line, and facilities used before this point of reference are upstream facilities used in gathering, whereas facilities employed after commingling at the central point and employed to make ultimate delivery of the gas are downstream facilities. 99 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MISSION RESOURCES CORPORATION By: /s/ Robert L. Cavnar ------------------------------------ Robert L. Cavnar Chairman and Chief Executive Officer Date: March 8, 2005 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURES TITLE DATE ---------- ----- ---- /s/ Robert L. Cavnar Chairman and Chief Executive Officer March 8, 2005 ------------------------------------------------ (principal executive officer) Robert L. Cavnar /s/ Richard W. Piacenti Executive Vice President and March 8, 2005 ------------------------------------------------ Chief Financial Officer Richard W. Piacenti (principal financial officer) /s/ Ann Kaesermann Vice President -- Accounting and March 8, 2005 ------------------------------------------------ Investor Relations, Ann Kaesermann Chief Accounting Officer (principal accounting officer) /s/ David A.B. Brown Director March 8, 2005 ------------------------------------------------ David A.B. Brown /s/ Joseph N. Jaggers Director March 8, 2005 ------------------------------------------------ Joseph N. Jaggers /s/ Robert R. Rooney Director March 8, 2005 ------------------------------------------------ Robert R. Rooney /s/ Herbert C. Williamson III Director March 8, 2005 ------------------------------------------------ Herbert C. Williamson III
100 EXHIBIT INDEX 2.1 Agreement and Plan of Merger dated January 24, 2001 between the Company and Bargo Energy Company (incorporated by reference to Exhibit 2.1 to the Company's 8-K filed on January 26, 2001). 3.1 Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement No. 33-76570 filed on March 17, 1994). 3.2 Certificate of Amendment to Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K filed on September 27, 1997). 3.3 Certificate of Designation, Preferences and Rights of the Series A Preferred Stock of the Company (incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K filed on September 27, 1997). 3.4 Certificate of Merger of Bargo Energy Company into the Company (incorporated by reference to Exhibit 3.4 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 3.5 Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.5 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 3.6 By-laws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement No. 33-76570 filed on March 17, 1994). 3.7 Amendment to the Company's Bylaws adopted on November 21, 1997 (incorporated by reference to Exhibit 3.5 to the Company's Annual Report on Form 10-K filed on March 27, 1998). 3.8 Amendment to the Company's Bylaws adopted on March 27, 1998 (incorporated by reference to Exhibit 3.6 to the Company's Annual Report on Form 10-K filed on March 27, 1998). 4.1 Specimen Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 4.2 Rights Agreement between the Company and American Stock Transfer & Trust Company (incorporated herein by reference to Exhibit 1 to the Company's Registration Statement on Form 8-A filed on September 19, 1997). 4.3 Amendment to Rights Agreement dated as of December 17, 2003, by and between Mission Resources Corporation and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on December 18, 2003). 4.4 Amendment to Rights Agreement dated as of February 25, 2004, by and between the Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on February 26, 2004). 4.5 Amendment to Rights Agreement dated as of March 15, 2004 by and between the Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on March 16, 2004). 4.6 Indenture dated as of May 29, 2001 among the Company, the Subsidiary Guarantors named therein and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-4 filed on July 27, 2001). 4.7 Registration Rights Agreement dated December 17, 2003, by and among the Company and FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income Series (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on December 18, 2003). 4.8 Registration Rights Agreement dated February 25, 2004, by and among the Company and Stellar Funding Ltd. (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on February 26, 2004). 4.9 Registration Rights Agreement dated March 15, 2004, by and between the Company and Harbert Distressed Investment Master Fund, Ltd. (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on March 16, 2004). 4.10 Indenture dated as of April 8, 2004, among the Company, the Guarantors named therein and The Bank of New York, as Trustee, relating to the Company's 9 7/8% Senior Notes due 2011 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K/A filed on April 15, 2004).
10.1+ 1994 Stock Incentive Plan (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement No. 33-76570 filed on March 17, 1994). 10.2+ 1996 Stock Incentive Plan (incorporated by reference to Exhibit A to the Company's Proxy Statement on Schedule 14A filed on October 21, 1996). 10.3+ 2004 Incentive Plan (incorporated by reference to Appendix C to the Company's Proxy Statement on Schedule 14A filed on March 30, 2004). 10.4 Amended and Restated Credit Agreement, dated as of March 28, 2003, among the Company, Farallon Energy Funding, LLC, as Arranger and Lender, Jefferies & Company, Inc., as Syndica- tion Agent and Foothill Capital Corporation, as Administrative Agent (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, filed April 1, 2003). 10.5 Second Amended, Restated and Consolidated Guaranty and Collateral Agreement, dated as of march 28, 2003, made by the Company and certain of its Subsidiaries, in favor of Foothill Capital Corporation, as Administrative Agent (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K, filed April 1, 2003). 10.6 Second Amended and Restated Credit Agreement among the Company, as Borrower, the Several Lenders from Time to Time Parties Hereto, Farallon Energy Lending, L.L.C., as Arranger Jefferies & Company, Inc., as Syndication Agent and Wells Fargo Foothill, Inc., as Administrative Agent dated as of June 5, 2003 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K filed on June 17, 2003). 10.7 Third Amended, Restated And Consolidated Guaranty And Collateral Agreement, dated as of June 5, 2003, made by the Company and certain of its Subsidiaries, in favor of Wells Fargo Foothill, Inc., as Administrative Agent (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K filed on June 17, 2003). 10.8 First Amendment to and Waiver of Second Amended and Restated Credit Agreement, dated as of June 25, 2003, among the Company, the several banks and other financial institutions or entities from time to time parties to the Amendment, Farallon Energy Lending, L.L.C., as sole advisor, sole lead arranger and sole bookrunner, and Wells Fargo Foothill, Inc, as administrative agent (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed November 13, 2003). 10.9 Second Amendment, dated October 22, 2003, to the Second Amended and Restated Credit Agreement, dated as of June 5, 2003, by and among the Company, the several banks and other financial institutions or entities from time to time parties thereto, Farallon Energy Lending, L.L.C., as sole advisor, sole lead arranger and sole bookrunner, Jefferies & Company, Inc., as the syndication agent, and Wells Fargo Foothill, Inc, formerly known as Foothill Capital Corporation, as administrative agent (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed November 13, 2003). 10.10 Credit Agreement dated as of April 8, 2004, among the Company, as Borrower, Wells Fargo Bank, National Association, as Lead Arranger and Administrative Agent, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K/ A filed on April 15, 2004). 10.11 Term Loan Agreement dated as of April 8, 2004, among the Company, as Borrower, Guggenheim Corporate Funding, LLC, as Collateral Agent, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K/A filed on April 15, 2004). 10.12 Intercreditor Agreement dated as of April 8, 2004, by and between the Company, the Company's Subsidiaries, Wells Fargo Bank, National Association and Guggenheim Corporate Funding LLC (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K/A filed on April 15, 2004). 10.13 Purchase and Sale Agreement, dated as of March 28, 2003, by and between Farallon Capital Management, LLC and the Company, as Administrative Agent (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K, filed April 1, 2003). 10.14 Purchase and Sale Agreement, dated as of December 17, 2003, by and among the Company and FTVIPT -- Franklin Income Securities Fund and Franklin Custodian Funds -- Income Series (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on December 18, 2003).
10.15 Purchase and Sale Agreement, dated as of February 25, 2004, by and between the Company and Stellar Funding Ltd. (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on February 26, 2004). 10.16 Purchase and Sale Agreement, dated as of March 15, 2004, by and between the Company and Harbert Distressed Investment Master Fund, Ltd. (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on March 16, 2004). 10.17+ Employment Agreement dated August 8, 2002, between the Company and Robert L. Cavnar (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed November 14, 2002). 10.18+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Robert L. Cavnar (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.19+ Employment Agreement dated October 8, 2002, between the Company and Richard W. Piacenti (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed November 14, 2002). 10.20+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Richard W. Piacenti (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.21+ Employment Agreement dated November 7, 2002, between the Company and John L. Eells (incorporated by reference to Exhibit 10.14 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 10.22+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and John L. Eells (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.23+ Employment Agreement dated November 6, 2002, between the Company and Joseph G. Nicknish (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K filed on March 31, 2003). 10.24+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Joseph G. Nicknish (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.25+ Severance Agreement dated November 17, 2004, between the Company and Joseph G. Nicknish (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 23, 2004). 10.26+ Employment Agreement effective November 4, 2003 between the Company and Marshall L. Munsell (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed on November 13, 2003). 10.27+ First Amendment to Employment Agreement dated November 9, 2004 between the Company and Marshall L. Munsell (incorporated by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.28*+ Employment Agreement dated as of November 1, 2004, between the Company and Thomas C. Langford. 10.29+ Non-statutory Stock Option Agreement dated as of November 1, 2004, between the Company and Thomas C. Langford (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 2, 2004). 10.30+ Form of Indemnification Agreement between the Company and each of its directors and executive officers (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed November 14, 2002). 10.31+ Form of Nonstatutory Stock Option Grant Agreement under the Company's 2004 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.32+ Form of Director Non-Qualified Stock Option (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004). 10.33+ Form of Incentive Stock Option Grant Agreement under the Company's 2004 Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed November 10, 2004).
10.34*+ First Amendment to the Employment Agreement dated as of November 1, 2004, between the Company and Thomas C. Langford. 21.1* Subsidiaries of the Company. 23.1* Consent of KPMG LLP. 23.2* Consent of Netherland Sewell & Associates, Inc. 31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended. 31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended. 32.1* Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive Officer of the Company. 32.2* Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial Officer of the Company.
--------------- * Filed herewith. + Management contract or compensatory plan or arrangement