10-K 1 fullkrpt.txt __________________________________________________ Securities and Exchange Commission Washington, D.C. 20549 Form 10-K (mark one) [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2001 Or [ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Transition Period from to Commission file number 0-17267 Mallon Resources Corporation (Exact name of registrant as specified in its charter) Colorado 84-1095959 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 999 18th Street, Suite 1700 Denver, Colorado 80202 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: (303) 293-2333 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.01 per share (Title of Class) Indicate by check mark whether the registrant (l) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: [X] Yes [ ] No As of the close of business on March 15, 2002, the aggregate market value of the shares of voting stock held by non-affiliates of the registrant, based upon the sales price for a share of the registrant's Common Stock as reported on the Nasdaq National Market tier of the Nasdaq Stock Market, was approximately $14,114,000. As of March 15, 2002, 10,867,827 shares of the registrant's Common Stock, par value $0.01 per share, were outstanding. 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 the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment hereto. [X] __________________________________________________ Mallon Resources Corporation Form 10-K for the fiscal year ended December 31, 2001 Table of Contents PART I Page Items 1- 2 Business and Properties. . . . . . . . . . . . . . . . . . . . . 1 General History . . . . . . . . . . . . . . . . . . . . . . . 1 Business Strategies. . . . . . . . . . . . . . . . . . . . . . 1 Historical Highlights . . . . . . . . . . . . . . . . . . . . 1 Our Oil and Gas Properties . . . . . . . . . . . . . . . . . . 2 Gas Sweetening Plant. . . . . . . . . . . . . . . . . . . . . 3 Acreage. . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Summary Oil and Gas Reserve Data. . . . . . . . . . . . . . . 3 Drilling Activity. . . . . . . . . . . . . . . . . . . . . . . 3 Recompletion Activity. . . . . . . . . . . . . . . . . . . . . 4 Productive Wells. . . . . . . . . . . . . . . . . . . . . . . 4 Production and Sales. . . . . . . . . . . . . . . . . . . . . . 4 Marketing. . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Corporate Offices; Officers, Directors and Key Employees. . . . 5 Cautionary Statement Regarding Forward-Looking Statements. . . 6 Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . 6 Item 3 Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . 12 Item 4 Submission of Matters to a Vote of Security Holders. . . . . . 12 PART II Item 5 Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . . . . 13 Price Range of Common Stock. . . . . . . . . . . . . . . . . 13 Holders. . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Dividend Policy. . . . . . . . . . . . . . . . . . . . . . . 13 Item 6 Selected Financial Data. . . . . . . . . . . . . . . . . . . . 14 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations. . . . . . . . . . . . . . . . . 15 Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Critical Accounting Policies. . . . . . . . . . . . . . . . 15 Contractual Commitments and Obligations. . . . . . . . . . . 16 Liquidity and Capital Resources. . . . . . . . . . . . . . . 17 Results of Operations. . . . . . . . . . . . . . . . . . . . 20 Hedging Activities. . . . . . . . . . . . . . . . . . . . . 23 Miscellaneous. . . . . . . . . . . . . . . . . . . . . . . . 23 Item 7A Quantitative and Qualitative Disclosure about Market Risk. . . 24 Commodity Price Risk. . . . . . . . . . . . . . . . . . . . . 24 Interest Rate Risk. . . . . . . . . . . . . . . . . . . . . . 24 Item 8 Financial Statements and Supplementary Data. . . . . . . . . . 24 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . . . . . . . . 24 PART III Item 10 Directors and Executive Officers of the Registrant. . . . . . .25 Item 11 Executive Compensation Item 12 Security Ownership of Certain Beneficial Owners and Management. 26 Item 13 Certain Relationships and Related Transactions. . . . . . . . .27 PART IV Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . 28 SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29 EXHIBIT INDEX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 GLOSSARY OF CERTAIN INDUSTRY TERMS. . . . . . . . . . . . . . . . . . . . . 31 CONSOLIDATED FINANCIAL STATEMENTS Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . F-1 Report of Independent Public Accountants . . . . . . . . . . . . . . . . . F-2 Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-3 Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . F-4 Consolidated Statements of Shareholders' Equity . . . . . . . . . . . . . .F-5 Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-7 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . F-8 PART I ITEMS 1 AND 2: BUSINESS AND PROPERTIES General History As used in this report, any reference to "Mallon," "we," "our" or the "Company" means Mallon Resources Corporation and its subsidiaries, unless the context suggests otherwise. We have included definitions of technical terms and abbreviations important to an understanding of our business under "Glossary of Certain Industry Terms." We are an independent energy company engaged in oil and natural gas exploration, development and production. We conduct our operations through our wholly-owned subsidiary, Mallon Oil Company. We operate primarily in the State of New Mexico, where all of our estimated proved reserves are located in the San Juan Basin, where we have been active since 1984. As of December 31, 2001, our proved reserves consisted of 53.1 billion cubic feet of natural gas and 27,800 barrels of crude oil, with a pre-tax PV-10 of $25.6 million. At December 31, 2001, we owned interests in 166 gross (134 net) producing wells and operated 145, or 87%, of them. Our common stock is traded on the Nasdaq National Market tier of the Nasdaq Stock Market under the symbol "MLRC." Our executive offices are at 999 18th Street, Suite 1700, Denver, Colorado 80202 (telephone 303/293-2333). Our transfer agent is Securities Transfer Corporation, Frisco, Texas. Business Strategies Our primary business objective is to increase our proved oil and gas reserves and cash flows. We pursue this objective by: - Conducting Exploration through Exploitation. Our primary operating strategy is to increase our proved reserves through relatively low-risk activities such as development drilling, recompletions, multi-zone completions and enhanced recovery activities. Numerous potentially productive geologic formations tend to be stacked atop one another in the San Juan Basin. This allows us to target multiple potential pay zones in most wells, thus reducing drilling risks, and to conduct exploration operations in conjunction with our development drilling. Wells drilled to one horizon offer opportunities to examine up-hole zones or can be drilled to deeper prospective formations for relatively little additional cost. - Controlling Our Operations. For the year ended December 31, 2001, approximately 95% of our production was from properties that we operate. We believe that this level of operating control, combined with our operating experience in the San Juan Basin, allows us to better control ongoing operations and costs, field development decisions, and the timing and nature of capital expenditures. - Developing and Controlling Our Infrastructure. By owning and controlling our critical infrastructure, such as gas gathering systems, gas sweetening plants and produced water disposal facilities, we believe that we can better manage our costs. Historical Highlights In September 1993, we purchased a group of Delaware Basin properties from Pennzoil Exploration and Production Company. In January 1997, we acquired additional interests in our key San Juan Basin gas property, East Blanco Field, and became operator of the field. In October 1996, December 1997, and September 2000, we completed public financings in which we sold an aggregate of 7.3 million shares of common stock for combined net proceeds of $48.1 million. These financings, together with our debt financing from Aquila Energy Capital Corporation ("Aquila"), enabled us to develop our inventory of oil and gas properties. In May 1998, we significantly increased our acreage in East Blanco Field in the San Juan Basin by entering into a Minerals Development Agreement ("MDA") with the Jicarilla Apache Nation. This acreage is adjacent to our original East Blanco acreage. Portions of this MDA, consisting of undeveloped wildcat acreage, were allowed to expire in September 2001, resulting in current holdings in the field of approximately 51,300 acres. In April 2000, we received permission to commingle the gas produced from different zones in our East Blanco wells. Prior to this approval, wells in the field were limited to producing from not more than two zones at a time. Commingling, which permits us to produce gas from multiple producing formations at the same time, results in improvements in well economics. We plan to commingle the production from most new wells that we drill at East Blanco, and to recomplete selected older wells in order to commingle their production. In September 2001, we completed the sale of all of our oil and gas properties located in the Delaware Basin in southeast New Mexico. The sale included our interests in 23 fields, consisting of interests in 141 producing wells and 13,742 net mineral acres. The adjusted purchase price received was approximately $31.5 million. We applied approximately $24.1 million of the proceeds to reduce our debt to Aquila by approximately 47%. Our Oil and Gas Properties We are active in the San Juan Basin of northwestern New Mexico. At December 31, 2001, this area accounted for substantially all of our approximately 53.3 Bcfe of estimated proved reserves. We have been active in the San Juan Basin since 1984, where our primary area of interest is our East Blanco natural gas field. At December 31, 2001, we owned interests in approximately 58,400 gross (55,000 net) acres of oil and gas properties in the San Juan Basin. Wells on this acreage produce from a variety of zones in the San Jose, Nacimiento, Ojo Alamo, Pictured Cliffs, Mesaverde, Mancos and Dakota formations. We plan to commence pilot programs to test the Fruitland Coal Formation and Lewis Shale, which are present throughout much of our East Blanco acreage. We will need to obtain additional capital or joint venture partners in order to undertake these projects. East Blanco Field, Rio Arriba County, New Mexico We own interests in approximately 51,300 gross (50,000 net) acres in the East Blanco natural gas field on the eastern flank of the San Juan Basin. We have been involved in the development of East Blanco Field since 1986. All production in the field has been natural gas. East Blanco wells typically contain reserves in one or more of the following productive zones: the Pictured Cliffs Sandstone at approximately 3,600 feet, the Ojo Alamo Sandstone at approximately 3,000 feet, the Nacimiento Formation at approximately 2,000 feet and the San Jose Formation at approximately 1,500 feet. The wells also penetrate the Fruitland Coal Formation at approximately 3,800 feet, which is productive in fields adjacent to East Blanco. The Lewis Shale, at approximately 5,500 feet, also underlies most of our East Blanco acreage. We operate all 134 of our East Blanco Field wells, in which we have an average working interest of approximately 94% and an average net revenue interest of approximately 75%. As of December 31, 2001, our estimated proved reserves in East Blanco Field were approximately 52.3 Bcfe, or approximately 98% of our total estimated proved reserves. During 2001, we drilled 21 wells and recompleted 1 well at East Blanco. This drilling and recompletion work was done primarily to put Pictured Cliffs, Ojo Alamo, Nacimiento and San Jose gas on production. Based on our operations to date, we have identified more than 200 remaining drilling and recompletion opportunities on our East Blanco acreage. Other San Juan Basin Fields Gavilan Field, Rio Arriba County, New Mexico. We own and operate seven wells in this field, in which our average working interest is approximately 44%. We have leasehold interests in approximately 2,400 gross (1,260 net) acres in this field. Current production is primarily natural gas from the Mancos Shale at approximately 6,900 feet and from the Mesaverde Formation at approximately 5,400 feet. As of December 31, 2001, Gavilan Field contained approximately 0.7 Bcfe or approximately 1% of our total estimated proved reserves. Otero Field, Rio Arriba County, New Mexico. We own and operate three wells in this field, in which our average working interest is approximately 95%. We have leasehold interests in approximately 4,600 gross (3,700 net) acres in this field. The wells produce oil from the Mancos Shale at approximately 4,700 feet. As of December 31, 2001, Otero Field contained only a nominal portion of our total estimated proved reserves. Other Areas All of our oil and gas operations are currently conducted on-shore in the United States. In addition to the properties described above, we have interests in properties in the states of Colorado, Oklahoma, North Dakota and Alabama. While we intend to continue to produce our existing wells in those states, we currently do not expect to engage in any development activities in those areas. In 1999, we bid to obtain certain oil and gas concession rights in Costa Rica. We have been advised that our bids, for concessions covering a total of approximately 2.35 million acres, have been accepted, but concession contracts have yet to be signed. Gas Sweetening Plant We designed, constructed, own and operate an amine plant to remove the hydrogen sulfide from the gas produced at East Blanco. This plant treats the majority of the natural gas we produce at East Blanco. The plant's current capacity is 32 MMcf per day. With added compression, the plant's capacity can be increased to approximately 60 MMcf per day, without requiring substantial expansion. Acreage We believe we have satisfactory title to our oil and gas properties based on standards prevalent in the oil and gas industry, subject to exceptions that do not detract materially from the value of the properties. The following table summarizes our oil and gas acreage holdings as of December 31, 2001:
Developed Undeveloped Area Gross Net Gross Net San Juan Basin 25,077 22,057 33,281 32,917 Other 6,440 930 1,688 156 Total 31,517 22,987 34,969 33,073 ====== ====== ====== ======
Summary Oil and Gas Reserve Data The following table sets forth summary information concerning our estimated proved oil and gas reserves as of December 31, 2001, based on a report prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Netherland, Sewell & Associates, Inc. is sometimes referred to herein as the "Independent Engineer," and its report is sometimes referred to herein as the "Reserve Report." All calculations in the Reserve Report have been made in accordance with the rules and regulations of the Securities and Exchange Commission and give no effect to federal or state income taxes otherwise attributable to estimated future net revenues from the sale of oil and gas. The present value of estimated future net revenues has been calculated using a discount factor of 10%. The commodity prices used in this calculation were $1.92 per Mcf for natural gas and $16.50 per barrel for oil.
December 31, 2001 Proved Reserves: Natural gas (MMcf) 53,139 Oil (MBbl) 28 Total (MMcfe) 53,307 Proved Developed Reserves: Natural gas (MMcf) 37,635 Oil (MBbl) 16 Total (MMcfe) 37,731 PV-10 (in thousands): $25,657
Drilling Activity The following table reflects our drilling activities for each of the last three years:
Gross Wells Net Wells Productive Dry Total Productive Dry Total 1999 21 1 22 18.05 1.00 19.05 2000 27 1 28 26.72 1.00 27.72 2001 19 2 21 19.00 2.00 21.00
Recompletion Activity The following table contains information concerning our well recompletion activities for each of the last three years:
Gross Wells Net Wells Productive Dry Total Productive Dry Total 1999 6 1 7 5.67 0.92 6.59 2000 10 0 10 8.42 0 8.42 2001 2 0 2 .73 0 .73
Productive Wells The following table summarizes our gross and net interests in productive wells at December 31, 2001. Net interests represented in the table are net "working interests," which bear the cost of operations.
Gross Wells Net Wells Oil Natural Gas Total Oil Natural Gas Total San Juan Basin 4 139 143 3.39 127.54 130.93 Other 12 11 23 .74 2.63 3.37 Total 16 150 166 4.13 130.17 134.30 == === === ==== ====== ======
Production and Sales The following table sets forth information concerning our total oil and gas production and sales for each of the last three fiscal years:
Year Ended December 31, 2001 2000 1999 Net Production: Natural gas (MMcf) 5,954 6,022 5,600 Oil (MBbl) 105 171 172 Total (MMcfe) 6,584 7,048 6,632 Average Sales Price Realized (1): Natural gas (per Mcf) $ 2.83 $ 2.10 $ 1.81 Oil (per Bbl) $23.97 $24.43 $17.38 Per Mcfe $ 2.94 $ 2.38 $ 1.98 Average Cost (per Mcfe): Production tax and marketing expense $ 0.56 $ 0.49 $ 0.25 Lease operating expense (2) $ 1.27 $ 0.59 $ 0.52 Depletion $ 0.98 $ 0.79 $ 0.65
___________________ (1) Includes effects of hedging. (2) Lease operating expense in 2001 includes assessments for possessory interest taxes, interest and penalties of $2.2 million for 1998-2000 and $1.1 million for 2001 which we are protesting. Marketing Our natural gas is generally sold on the spot market or pursuant to short- term contracts. Oil and liquids are generally sold on the open market to unaffiliated purchasers, generally pursuant to purchase contracts that are cancelable on 30 days notice. The price paid for this production is generally an established or posted price that is offered to all producers in the field, plus any applicable differentials. Prices paid for crude oil and natural gas fluctuate substantially. Because future prices are difficult to predict, we hedge a portion of our oil and gas sales to protect against market downturns. The nature of hedging transactions is such that producers forego the benefit of some price increases that may occur after the hedging arrangement is in place. We nevertheless believe that hedging is prudent in certain circumstances in order to minimize the risk of falling prices. Under our credit agreement with Aquila, we are required to maintain price hedging arrangements in place with respect to up to 65% of our oil and gas production. In addition, we also entered into an agency agreement with Aquila under which we pay a marketing fee equal to 1% of the net proceeds (as defined) from the sale of our oil and gas production to market our gas and to negotiate our gas purchase contracts. Corporate Offices; Officers, Directors and Key Employees Our executive offices are located at 999 18th Street, Suite 1700, Denver, Colorado 80202, where our phone number is (303) 293-2333. We employ 17 employees at this office. We maintain a field operations office in Durango, Colorado, where we employ a total of 13 individuals. The following are the members of our Board of Directors and our executive officers: Name Age Title(s) George O. Mallon, Jr 57 Director, Chairman of the Board, CEO and President Roy K. Ross 51 Director, Executive Vice President, Secretary and General Counsel Peter H. Blum 44 Director, Executive Vice President Frank Douglass 68 Director Roger R. Mitchell 69 Director Francis J. Reinhardt, Jr. 72 Director Alfonso R. Lopez 53 Vice President - Finance and Treasurer The directors serve until the next annual meeting of shareholders. Following are brief descriptions of the business experience of our directors and executive officers: George O. Mallon, Jr. has been our President and Chairman of the Board since December 1988, when we were organized. He formed Mallon Oil in 1979. Mr. Mallon earned a B.S. degree in Business from the University of Alabama in 1965 and an M.B.A. degree from the University of Colorado in 1977. Roy K. Ross has been Executive Vice President and General Counsel of Mallon since 1992. He was named Secretary of Mallon in 1997. From June 1976 through September 1992, Mr. Ross was an attorney in private practice with the Denver-based law firm of Holme Roberts & Owen. Mr. Ross is also Executive Vice President, Secretary, General Counsel and a director of Mallon Oil. He earned his B.A. degree in Economics from Michigan State University in 1973 and his J.D. degree from Brigham Young University in 1976. Peter H. Blum became a director of Mallon in January 1998. He became an Executive Vice President of Mallon in September 2001. Since October 1998, Mr. Blum, a financial consultant, has been President of Bear Ridge Capital LLC. From April 1997 to October 1998, Mr. Blum was Senior Managing Director, head of investment banking, for the investment banking firm Gaines, Berland Inc. From 1995 to 1997, Mr. Blum held the position of Managing Director, head of energy banking, with the investment banking firm Rodman & Renshaw, Inc. From 1992 to 1995, Mr. Blum held various positions with the investment banking firm Mabon Securities, Inc. Mr. Blum earned a B.B.A. degree in accounting from the University of Wisconsin in 1979. Frank Douglass has been a director of Mallon since its formation in 1988. In 1998, he retired as a Senior Partner in the Texas law firm of Scott, Douglass & McConnico, LLP, where he had been a partner since 1976. Mr. Douglass earned a B.B.A. degree from Southwestern University in 1953 and a L.L.B. degree from the University of Texas School of Law in 1958. Roger R. Mitchell has been a director of Mallon since 1990. Prior to 1989, Mr. Mitchell served as a co-general partner with Mallon of a series of private oil and gas drilling limited partnerships sponsored by Mallon. Mr. Mitchell has participated in or managed a number of real estate, insurance and investment companies, including Mitchell Management Company, which he currently owns. He earned a B.S. degree in Business from Indiana University in 1954 and an M.B.A. degree from Indiana University in 1956. Francis J. Reinhardt, Jr. has been a director of Mallon since 1994. He is with the New York investment banking firm of Carl H. Pforzheimer & Co., where he has been a partner since 1966. He is a member and past president of the National Association of Petroleum Investment Analysts. Mr. Reinhardt is also a director of The Exploration Company of Louisiana, a public company engaged in the oil and gas business. Mr. Reinhardt holds a B.S. degree from Seton Hall University and an M.B.A. from New York University. Alfonso R. Lopez joined Mallon in July 1996 as Vice President-Finance and Treasurer. He was Vice President - Finance for Consolidated Oil & Gas, Inc. (now Chesapeake Energy Corporation) from 1993 to 1995. Mr. Lopez was a consultant from 1991 to 1992. From 1981 to 1990, he was Controller for Decalta International Corporation, a Denver-based exploration and production company. He served as Controller for Western Crude Oil, Inc. (now Texaco Trading and Transportation, Inc.) from 1978 to 1981. Mr. Lopez is a certified public accountant and was with Arthur Young & Company (now Ernst & Young) from 1970 to 1978. Mr. Lopez earned his B.A. degree in Accounting and Business Administration from Adams State College in Colorado in 1970. Key Employees Employees who are instrumental to our success include the following individual: Donald M. Erickson, Jr. was named Senior Vice President and General Manager of Mallon Oil in June 2001. Prior to that time he was Vice President - Operations of Mallon Oil since February 1997. Mr. Erickson has more than 20 years of experience in oil field operations. Prior to joining Mallon, he was Operations Manager for Presidio Exploration, Inc. (which was merged into Tom Brown Inc.) from December 1988 to January 1997. Mr. Erickson earned a Heating and Cooling Technical Degree from Central Technical Community College in Hastings, Nebraska in 1975 and has studied Mechanical Engineering at the University of Colorado, Denver. Cautionary Statement Regarding Forward-Looking Statements This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements regarding, among other items, our growth strategies, the potential for the recovery of additional volumes of hydrocarbons, anticipated trends in our business and our future results of operations, market conditions in the oil and gas industry, our ability to make and integrate acquisitions, the outcome of litigation and the impact of governmental regulation. These forward-looking statements are based largely on our expectations and are subject to a number of risks and uncertainties, many of which are beyond our control. Actual results could differ materially from these forward-looking statements as a result of, among other things: - a decline in natural gas production or natural gas prices, - incorrect estimates of required capital expenditures, - increases in the cost of drilling, completion and gas collection or other costs of production and operations, - an inability to meet growth projections, and - other risk factors set forth under "Risk Factors" below. In addition, the words "believe," "may," "will," "estimate," "continue," "anticipate," "intend," "expect" and similar expressions, as they relate to Mallon, our business or our management, are intended to identify forward- looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this report. In light of these risks and uncertainties, the forward-looking events and circumstances discussed in this report may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements. Risk Factors In evaluating us and our common stock, readers should consider carefully, among other things, the following risk factors. Oil and gas prices are volatile, and an extended decline in prices could adversely affect our revenue, cash flows and profitability. Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for oil and gas. We expect the markets for oil and gas to continue to be volatile. Any substantial or extended decline in the price of oil or gas would have a material adverse effect on our financial condition and results of operations. It could reduce our cash flow and borrowing capacity, as well as the value and the amount of our reserves. At December 31, 2001, substantially all of our estimated proved reserves were natural gas. Accordingly, we are impacted more directly by volatility in the price of natural gas. We cannot predict future oil and natural gas prices. Various factors beyond our control that could affect prices of oil and gas include: - worldwide and domestic supplies of oil and gas, - the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls, - political instability or armed conflict in oil or gas producing regions, - the price and level of foreign imports, - worldwide economic conditions, - marketability of production, - the level of consumer demand, - the price, availability and acceptance of alternative fuels, - the availability of pipeline capacity, - weather conditions, and - actions of federal, state, local and foreign authorities. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and gas. We enter into energy swap agreements and other financial arrangements at various times to attempt to minimize the effect of oil and natural gas price fluctuations. We cannot assure you that such transactions will reduce risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in oil or natural gas prices would have a material adverse effect on our business and financial results. Energy swap arrangements may limit the risk of declines in prices, but such arrangements may also limit revenues from price increases. Lower oil and gas prices may cause us to record ceiling limitation write- downs. We periodically review the carrying value of our oil and gas properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of cost or fair market value of the proved properties, as adjusted for related tax effects. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded. We may be required to write down the carrying value of our oil and gas properties when oil and gas prices are depressed or unusually volatile. If a write-down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and gas properties is not reversible at a later date. We recorded a $16.4 million write-down of the carrying value of our oil and gas properties in third quarter 2001 and a $16.8 million write-down in fourth quarter 1998. Our operations require large amounts of capital. Our current development plans will require us to make large capital expenditures for the exploration and development of our properties. Historically, we have funded our capital expenditures through a combination of funds generated internally from sales of production, equity offerings, and long and short-term debt financing arrangements. We currently do not have any sources of additional financing other than our existing credit agreement with Aquila and our equipment leases. We cannot be sure that any additional financing will be available to us on acceptable terms. Future cash flows and the availability of financing will be subject to a number of variables, such as: - the level of production from existing wells, - prices of oil and natural gas, and - our results in locating and producing new reserves and the results of our natural gas development project at East Blanco Field. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing shareholders. Debt financing could lead to: - a substantial portion of our operating cash flow being dedicated to the payment of principal and interest, - our being more vulnerable to competitive pressures and economic downturns, and - restrictions on our operations. If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facility or otherwise, our ability to execute our development plans, replace our reserves or maintain production levels could be greatly limited. Estimates in this report concerning our oil and gas reserves and future net revenue estimates are uncertain. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. Estimates of proved undeveloped reserves, which comprise a significant portion of our reserves, are by their nature uncertain. The reserve information included or incorporated by reference in this report are only estimates and are based upon various assumptions, including assumptions required by the Securities and Exchange Commission, relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although we believe they are reasonable, actual production, revenues and expenditures will likely vary from estimates, and these variances may be material. Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. In addition, you should not construe PV-10 as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flow, including: - prices for oil and natural gas, - the amount and timing of actual production, - supply and demand for oil and natural gas, - curtailments or increases in consumption by crude oil and natural gas purchasers, and - changes in governmental regulations or taxation. The timing of the production of oil and natural gas properties and of the related expenses affect the timing of actual future net cash flow from proved reserves and, thus, their actual present value. In addition, the 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. Our long-term financial success will depend on our ability to replace the reserves we produce. In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future development, acquisition and exploration activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. We depend heavily on successful development of our San Juan Basin properties. Our future success depends on our ability to develop additional natural gas reserves on our San Juan Basin properties that are economically recoverable. Most of our proved reserves are in the San Juan Basin, and our development plans make our future growth highly dependent on increasing production and reserves in the San Juan Basin. Our proved reserves will decline as reserves are depleted, except to the extent we conduct successful exploration or development activities or acquire other properties containing proved reserves. Our development plan includes increasing our reserve base through continued drilling and development of our existing properties in the San Juan Basin. Our San Juan Basin properties can only be effectively developed and evaluated by drilling activities and the evaluation of drilling results. Less costly means of evaluation, such as 3-D seismic, are not helpful on properties such as ours. We cannot be sure that our planned projects will lead to significant additional reserves or that we will be able to continue drilling productive wells at acceptable finding and development costs. The oil and gas exploration business involves a high degree of business and financial risk. The business of exploring for and, to a lesser extent, developing oil and gas properties is an activity that involves a high degree of business and financial risk. Property acquisition decisions generally are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately the ultimate production potential, if any, of a particular property or well. Moreover, the successful completion of an oil or gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. Our industry is subject to numerous hazards. The oil and natural gas industry involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us substantial losses. In addition, we may be liable for environmental damage caused by previous owners of property we own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. An event that is not fully covered by insurance -- for instance, losses resulting from pollution and environmental risks, which are not fully insurable -- could have a material adverse effect on our financial condition and results of operations. Further, our insurance may not be adequate to cover losses or liabilities and the insurance we do have may not continue to be available at premium levels that justify its purchase. Exploratory drilling is an uncertain process with many risks. Exploratory drilling involves numerous risks, including the risk that we will not find any commercially productive natural gas or oil reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including: - unexpected drilling conditions, - pressure or irregularities in formations, - equipment failures or accidents, - adverse weather conditions, - compliance with governmental requirements, and - shortages or delays in the availability of drilling rigs and the delivery of equipment. Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate, or our drilling success rate for activity within a particular area, will not decline. Unsuccessful drilling activities could have a material adverse effect on our results of operations and financial condition. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we cannot be sure that we will ever drill them or that we will produce oil or natural gas from them or any other potential drilling locations. Our key assets are concentrated in a small geographic area. The majority of our natural gas production is processed through our East Blanco gas sweetening plant. Our production, revenue and cash flow will be adversely affected if this plant's operation is shut down, curtailed or limited for any reason. Substantially all of our operations are currently located in one geologic basin in New Mexico. Because of this geographic concentration, any regional events that increase costs, reduce availability of equipment or supplies, reduce demand or limit production, including weather and natural disasters, may impact us more than if our operations were more geographically diversified. The availability of markets for our natural gas is beyond our control. Substantially all of our gas is produced in the San Juan Basin in the State of New Mexico and, consequently, we are particularly sensitive to marketing constraints that exist or may arise in the future in that area. Historically, due to the San Juan Basin's relatively isolated location and the resulting limited access of its natural gas production to the marketplace, natural gas produced in the San Juan Basin has tended to command prices that are lower than natural gas prices that prevail in other areas. Our business depends on transportation facilities owned by others. The marketability of our gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of gas and oil production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce, gather and transport natural gas. We face marketing, trading and credit risks. The marketability of our production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Federal, state and tribal regulation of oil and gas production and transportation could adversely affect our ability to produce and market oil and natural gas. In addition, the marketing of our oil and natural gas requires us to assess and respond to changing market conditions, including credit risks. If we are unable to respond accurately to changing conditions in the commodity markets, our results of operations could be materially adversely affected. We try to limit our exposure to price risk by entering into various hedging arrangements. We are exposed to credit risk because the counterparties to agreements might not perform their contractual obligations. Our hedging arrangements might limit the benefit of increases in commodity prices. To reduce our exposure to short-term fluctuations in the price of oil and natural gas, we enter into hedging arrangements from time to time with regard to a portion of our oil and natural gas production. These hedging arrangements limit the benefit of increases in the price of oil or natural gas while providing only partial protection against declines in prices. Under our credit agreement with Aquila, we are required to maintain price hedging arrangements in place with respect to up to 65% of our oil and gas production. Our industry is heavily regulated. Federal, state, tribal and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. Noncompliance with statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. State, tribal and local authorities regulate various aspects of oil and gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. We must comply with complex environmental regulations. Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and local governmental authorities. New laws or regulations, or changes to current legal requirements, could have a material adverse effect on our business. We could face significant liabilities to the government and third parties for discharging oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts of monies on investigations, litigation and remediation. Our failure to comply with applicable environmental laws and regulations could result in the assessment of administrative, civil or criminal penalties. We cannot be sure that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not materially adversely affect our results of operations and financial condition or that we will not face material indemnity claims with respect to properties we own or lease or have owned or leased. Our industry is highly competitive. We operate in a highly competitive environment. Major oil companies, independent producers, and institutional and individual investors are actively seeking oil and gas properties throughout the world, along with the equipment, labor and materials required to operate properties. Many of our competitors have financial and technological resources vastly exceeding those available to us. Many oil and gas properties are sold in competitive bidding processes, as to which we may lack technological information or expertise available to other bidders. We cannot be sure that we will be successful in acquiring and developing profitable properties in the face of this competition. We depend on key personnel. Our success will continue to depend on the continued services of our executive officers and a limited number of other senior management and technical personnel. Loss of the services of any of these people could have a material adverse effect on our operations. Unlike many other companies in our industry, we do not maintain "key man" insurance on the lives of any of our employees. We have employment agreements with four of our executives. Our operations have not been profitable. We recorded net losses for 1997, 1998, 1999, 2000 and 2001, of $3,704,000, $18,186,000, $2,777,000, $6,531,000 and $31,365,000, respectively. Our ability to continue in business and maintain our financing arrangements may be adversely affected by a continued lack of profitability. We do not pay dividends. We have never declared or paid any cash dividends on our common stock and have no intention to do so in the foreseeable future. Our articles of incorporation have provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment. Our articles of incorporation contain provisions that may have the effect of delaying or preventing a change in control. Our articles of incorporation authorize the Board of Directors to issue up to 10,000,000 shares of preferred stock without shareholder approval and to set the rights, preferences and other designations, including voting rights, of those shares as the Board may determine. 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 shareholders for their common stock. Our Board of Directors adopted a shareholder rights agreement designed to enhance the Board's ability to prevent an acquirer from depriving shareholders of the long-term value of their investment and to protect shareholders against attempts to acquire Mallon by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover of Mallon not supported by the Board, including a takeover that may be desired by a majority of our shareholders or involving a premium over the prevailing stock price. ITEM 3: LEGAL PROCEEDINGS In 1992, the Minerals Management Service commenced an audit of royalties payable on production from certain oil and gas properties in which we own an interest. The audit was initiated against the predecessor operator of the properties (Robert Bayless), but we have a significant interest in the resolution of the matters that arise out of the audit. On December 22, 2000, administrative decisions were rendered in the case of Robert L. Bayless, MMS- 98-0132-IND relating to so-called "dual-accounting" and "major portion" matters. Bayless has joined with one other producer to appeal the administrative rulings by filing Bayless v. United States Department of the Interior, No. 1:01CV00393, in the United States District Court for the District of Columbia. The law firm of Fulbright & Jaworski, L.L.P. (Washington, DC), is representing the producers. The primary issue in dispute is the manner in which so-called "major portion" prices are determined. If the MMS's proposed protocol is ultimately upheld, we will be liable for additional unpaid royalties, interest and (perhaps) penalties. If a more reasonable protocol is established, as we expect will be the case, our exposure for such items should be immaterial. As of June 30, 2001, the Revenue and Taxation Department of the Jicarilla Apache Nation (the "Nation") had issued to us Possessory Interest Tax assessments for 1998, 1999, 2000 and 2001 totaling $3.3 million, as adjusted, including related penalties and interest. We have paid the assessments under protest. We protested the assessments arguing that, among other things, certain rules and regulations promulgated in December 2000 by the Nation do not apply to the determination of Possessory Interest Tax for years prior to 2001. Our protests have been denied by the Nation's Revenue and Taxation Department. We have: 1) filed an appeal to the Nation's Tribal Court, 2) requested that the Legislative Council of the Nation grant us relief, and 3) engaged the New Mexico law firm of Modrall, Sperling, Roehl, Harris & Sisk, P.A., to represent us in this matter. The final outcome of this matter cannot yet be predicted. In June 2001, in connection with staff cuts that were a part of general corporate overhead reductions, we terminated our employment of several individuals. On August 14, 2001, one of those former employees filed a complaint in the Federal District Court for the District of New Mexico, in which he claims his employment was wrongfully terminated. That case, Costalez v. Mallon Oil, CIV-01 929, is in the very early stages of discovery. We have retained the law firm of Holme Roberts & Owen LLP to defend us and the other named defendants. We believe the allegations of the suit are wholly without merit, and intend to defend ourselves vigorously. This case is in the early stages of discovery, and no outcome can yet be predicted. ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Price Range of Common Stock Our common stock is traded on the Nasdaq National Market tier of the Nasdaq Stock Market under the symbol "MLRC." The following table sets forth, for the periods indicated, the high and low sale prices of the common stock as reported on the Nasdaq National Market.
High Low Year Ending December 31, 2000: First Quarter $6.250 $3.813 Second Quarter 9.750 5.250 Third Quarter 8.750 6.063 Fourth Quarter 7.688 4.938 Year Ending December 31, 2001: First Quarter 8.375 5.875 Second Quarter 8.250 5.300 Third Quarter 5.960 2.000 Fourth Quarter 3.650 2.190 Year Ending December 31, 2002: First Quarter (through March 15) 3.040 0.900
Holders As of March 15, 2002, there were approximately 600 shareholders of record of the common stock. Dividend Policy We do not intend to pay cash dividends on our common stock in the foreseeable future. We instead intend to retain any earnings to support our growth. Any future cash dividends would depend on future earnings, capital requirements, our financial condition and other factors deemed relevant by our Board of Directors. Under the terms of our credit facility with Aquila, we may not pay dividends without the consent of Aquila. For a description of the credit facility, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." ITEM 6: SELECTED FINANCIAL DATA The following table sets forth selected consolidated financial data for each of the years in the five-year period ended December 31, 2001. This information should be read in conjunction with the consolidated financial statements and "Management's Discussion of Financial Condition and Results of Operations," included elsewhere herein.
Year Ended December 31, 2001 2000 1999 1998 1997 Selected Statements of Operations Data: (In thousands, except per share data) Revenues: Oil and gas sales $ 19,340 $ 16,803 $ 13,138 $ 13,069 $ 8,582 Other 425 504 160 109 69 19,765 17,307 13,298 13,178 8,651 Costs and expenses: Oil and gas production (1) 12,049 7,595 5,107 5,273 3,037 Depreciation, depletion and amortization 7,399 6,382 4,822 5,544 2,725 Impairment of oil and gas properties 16,418 -- -- 16,842 24 Impairment of mining properties -- -- -- -- 350 Loss on sale of oil and gas properties 3,109 -- -- -- -- General and administrative 6,439 3,609 2,915 2,562 2,274 Interest and other 5,716 6,252 3,126 1,143 701 51,130 23,838 15,970 31,364 9,111 Equity in loss of affiliate -- -- -- -- (3,244) Loss before extraordinary item (31,365) (6,531) (2,672) (18,186) (3,704) Extraordinary loss on early retirement of debt -- -- (105) -- -- Net loss (31,365) (6,531) (2,777) (18,186) (3,704) Accretion of mandatorily redeemable common stock (605) (428) (116) -- -- Dividends on preferred stock and accretion (21) (85) (120) (120) (185) Preferred stock conversion inducement -- -- -- -- (403) Net loss attributable to common shareholders $(31,991) $ (7,044) $ (3,013) $(18,306) $(4,292) ======== ======== ======== ======== ======= Per Share Data: Loss attributable to common shareholders before extraordinary item $ (2.99) $ (0.83) $ (0.40) $ (2.61) $ (0.92) Extraordinary loss -- -- (0.01) -- -- Net loss attributable to common shareholders $ (2.99) $ (0.83) $ (0.41) $ (2.61) $ (0.92) ======== ======== ======== ======== ======= Weighted average shares outstanding 10,686 8,525 7,283 7,015 4,682 Other Data: Capital expenditures $ 17,510 $ 18,207 $ 9,852 $ 36,354 $20,169 Selected Balance Sheet Data: Working capital (deficit) $ 54 $ 377 $(2,678) $ (3,782) $ 1,190 Total assets 37,971 91,710 65,426 58,452 51,426 Long-term debt (2) 28,970 40,180 34,874 27,183 1 Mandatorily redeemable preferred stock -- 798 1,341 1,329 1,317 Mandatorily redeemable common stock (3) 4,853 4,248 3,450 -- -- Shareholders' (deficit) equity (599) 28,536 19,490 22,164 40,196
(1) Lease operating expense for 2001 includes assessments for possessory interest taxes, interest and penalties of $2.2 million for 1998-2000 and $1.1 million for 2001, which were paid in 2001 under protest. (2) Long-term debt includes long-term debt net of current maturities and unamortized discount, notes payable-other and lease obligations net of current portion. (3) Represents the obligation to purchase 490,000 shares of common stock from a shareholder for a price of $12.50 per share in September 2003. See Note 6 to our consolidated financial statements. ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in understanding our historical consolidated financial position at December 31, 2001 and 2000, and results of operations and cash flows for each of the years ended December 31, 2001, 2000 and 1999. Our historical consolidated financial statements and notes thereto included elsewhere in this report contain detailed information that should be referred to in conjunction with the following discussion. Overview Our revenues, profitability and future growth rates will be substantially dependent upon our drilling success in the San Juan Basin, and prevailing prices for natural gas, which are in turn dependent upon numerous factors that are beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been volatile, and natural gas prices can be expected to continue to be subject to wide fluctuations in the future. A substantial or extended decline in gas prices could have a material adverse effect on our financial position, results of operations and access to capital, as well as the quantities of gas reserves that we may produce economically. Critical Accounting Policies The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 1 to the consolidated financial statements. Use of Estimates and Significant Risks: The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make significant estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. The more significant areas requiring the use of estimates relate to oil and gas reserves, fair value of financial instruments, valuation allowance for deferred tax assets, and useful lives for purposes of calculating depreciation, depletion and amortization. Actual results could differ from those estimates. Our operations are subject to numerous risks and uncertainties. Among these are risks related to the oil and gas business (including operating risks and hazards and the regulations imposed thereon), risks and uncertainties related to the volatility of the prices of oil and gas, uncertainties related to the estimation of reserves of oil and gas and the value of such reserves, the effects of competition and extensive environmental regulation, and many other factors, many of which are necessarily out of our control. The nature of oil and gas drilling operations is such that the expenditure of substantial drilling and completion costs are required well in advance of the receipt of revenues from the production developed by the operations. Thus, it will require more than several quarters for the financial success of that strategy to be demonstrated. Drilling activities are subject to numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. Oil and Gas Properties: Oil and gas properties are accounted for using the full cost method of accounting. Under this method, all costs associated with property acquisition, exploration and development are capitalized, including general and administrative expenses directly related to these activities. All such costs are accumulated in one cost center, the continental United States. See Note 2 to the consolidated financial statements for a complete discussion of our oil and gas properties. Proceeds on disposal of properties are ordinarily accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustment would significantly alter the relationship between capitalized costs and proved oil and gas reserves. Net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. Depletion is calculated using the units-of-production method based upon the ratio of current period production to estimated proved oil and gas reserves expressed in physical units, with oil and gas converted to a common unit of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Estimated abandonment costs (including plugging, site restoration, and dismantlement expenditures) are accrued if such costs exceed estimated salvage values, as determined using current market values and other information. Abandonment costs are estimated based primarily on environmental and regulatory requirements in effect from time to time. At December 31, 2001 and 2000, in management's opinion, the estimated salvage values equaled or exceeded estimated abandonment costs. Full Cost Ceiling Test: Under the full cost accounting rules of the Securities and Exchange Commission, we review the carrying value of our oil and gas properties each quarter on a country-by-country basis. Under full cost accounting rules, net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. Application of these rules generally requires pricing future production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and requires a write-down if the "ceiling" is exceeded, unless the prices recover subsequent to the balance sheet date but before the financial statements for the quarter are issued. If a smaller write-down is calculated using the subsequent pricing, then the smaller amount may be recorded. Using price increases subsequent to September 30, 2001, we recorded a charge in third quarter 2001 to write-down our oil and gas properties by $16.4 million. Had we used the prices in effect at September 30, 2001, the write-down would have been $25.3 million. Hedging Activities: Our use of derivative financial instruments is limited to management of commodity price and interest rate risks. Gains and losses on such transactions are accounted for as part of the transaction being hedged. If an instrument is settled early, any gains or losses are deferred and recognized as part of the transaction being hedged. We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and gas price volatility. Commodity derivatives contracts, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices received by us. Prior to January 1, 2001, we accounted for our commodity derivatives contracts using the hedge (deferral) method of accounting. Under this method, realized gains and losses from our price risk management activities are recognized in oil and gas revenue when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses from commodity derivatives contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a commodity derivatives contract and actual oil and gas prices, a gain or loss would be recognized currently to the extent the commodity derivatives contract did not offset changes in actual oil and gas prices. On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS No. 137 and SFAS No. 138. Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not meet specific hedge accounting criteria or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in other comprehensive income/loss, a component of shareholders' equity, to the extent the hedge is effective. Contractual Commitments and Obligations In addition to the Aquila Credit Agreement, we had various other contractual obligations as of December 31, 2001. The following table lists our significant liabilities at December 31, 2001 including the Aquila Credit Agreement:
Payments Due by Period Less than After Contractual Obligations 1 Year 2-3 Years 4-5 Years 5 Years Total (In thousands) Aquila Credit Agreement $ -- $26,711 $-- $-- $26,711 Lease obligation to Universal Compression, Inc. 500 4,067 -- -- 4,567 Note payable to Bank One, Colorado 17 33 58 -- 108 Operating leases 238 65 -- -- 303 $755 $30,876 $58 $-- $31,689 ==== ======= === === =======
We lease our corporate offices in Denver, Colorado under the terms of an operating lease, which expires in January 2003. Yearly payments under the lease are approximately $150,000. The office lease in Durango, Colorado represents a commitment of $26,000 per year through September 2004. The remaining operating lease commitments represent equipment leases, which expire during 2002 through 2003. Liquidity and Capital Resources We have generated net losses of $31.4 million, $6.5 million and $2.8 million for the years ended December 31, 2001, 2000 and 1999, respectively. However, we have generated cash flows from operating activities of $1.1 million, $4.0 million and $2.4 million for the years ended December 31, 2001, 2000 and 1999, respectively. As discussed more fully in Note 2 to the consolidated financial statements, on September 14, 2001, we completed the sale of our Delaware Basin oil and gas properties. Consequently, our remaining operations are located primarily in the San Juan Basin of northwest New Mexico. We have minimal access to the capital necessary to continue to develop our properties in the San Juan Basin. Subsequent to year end, however, we were able to amend our credit facility to provide, among other things, for a $2.5 million increase in the borrowings available under the credit facility. In addition, we are currently seeking alternate methods of financing our discretionary capital expenditures for 2002, including joint ventures with industry partners. However, there is no assurance that we will be able to secure financing on terms acceptable to us. In addition, because production from the San Juan Basin is predominantly natural gas, we are particularly sensitive to changes in the price of natural gas. Historically, natural gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in natural gas prices received could have a significant impact on our future results. If natural gas prices received decline significantly from those received at year end, or if we are unable to maintain production levels at our San Juan Basin properties, we may have to implement cost cutting measures in both our administrative and operating areas. As discussed more fully below, in conjunction with the February 2002 amendment to the Aquila Credit Agreement, through December 31, 2002, we are only required to make interest payments. We believe that cash on hand, available borrowings under the Aquila Credit Agreement and cash generated from operating activities will be sufficient to meet our cash requirements through December 31, 2002. Our operations are capital intensive. Historically, our principal sources of capital have been cash flow from operations, borrowings and proceeds from sales of stock. Our principal uses of capital have been for the acquisition, exploration and development of oil and gas properties and related facilities. During the year ended December 31, 2001, our capitalized costs incurred in oil and gas producing activities were $17.5 million. During 2001, we drilled 21 wells, of which 19 were successful, and recompleted two wells. We are currently evaluating the number of wells we will drill during 2002. We plan to fund our capital requirements for the next 12 months with additional financing or joint venture arrangements. We cannot be sure that any additional financing or joint ventures will be available to us on acceptable terms. As discussed above, on September 14, 2001, we completed the sale of our Delaware Basin properties, effective July 1, 2001, for an adjusted purchase price of approximately $31.5 million. After paying approximately $2.0 million of additional costs related to the sale, we received net proceeds of approximately $29.4 million, of which we used approximately $24.1 million to repay a portion of our note payable to Aquila. The remaining $5.3 million was used for operations. In October 2000, we issued 2,660,000 shares of our common stock in a public offering at a price of $6.25 per share. We received net proceeds, after commissions and other costs, of approximately $15.3 million, which was used primarily to finance our oil and gas drilling activities. In September 1999, we established a credit agreement (the "Aquila Credit Agreement") with Aquila. Through December 31, 2001, we had drawn $52.3 million, including accrued interest and repaid $25.6 million under the Aquila Credit Agreement. Approximately $24.1 million was repaid with the proceeds from the sale of our Delaware Basin properties in September 2001 as discussed above. The initial amount available under the Aquila Credit Agreement was $45.7 million. In November 2000, the Aquila Credit Agreement was amended and the amount available under the agreement was increased by $7.7 million, making the total available $53.4 million. Through December 31, 2001, we had drawn $52.3 million, including accrued interest, under the Aquila Credit Agreement, of which $28.0 million was used to retire the Bank One Facility in September 1999. Principal payments on the four-year loan began in November 1999 based on our cash flow from operations, as defined (the "Defined Cash Flow"), less advances for our development drilling program. Through December 31, 2000, we did not make any principal payments because drilling expenditures equaled or surpassed Defined Cash Flow during that period. We had expected to begin making principal payments in March 2001 in amounts equal to the Defined Cash Flow and paid Aquila $1.4 million on April 6, 2001. On March 30, 2001, we negotiated a change in the terms of our agreement with Aquila to delay the required repayment of principal. Instead, the repayment schedule for the twelve months beginning April 30, 2001 was to be as follows: (i) for the months April 2001 to September 2001, we paid interest only, or approximately $2.2 million, and (ii) from October 2001 to March 2002, we were to make monthly principal and interest payments of $700,000 or a total of $4.2 million. Aquila allowed us to make interest only payments totaling $505,000 for October 2001 to December 2001. In February 2002, we notified Aquila that as of December 31, 2001, we would not be in compliance with one of the covenants under the Aquila Credit Agreement. That covenant requires us to maintain projected net revenue attributable to our proved reserves in an amount sufficient to fully amortize the balance under the Aquila Credit Agreement by the maturity date of September 9, 2003. As a result, in February 2002, the Aquila Credit Agreement was amended for a second time, as follows: (i) As long as no new event of default occurs subsequent to the date of the second amendment, Aquila has agreed that through December 31, 2002, it will not exercise any of the remedies available to Aquila due to any event of default that occurs and is continuing regarding the amount of projected net revenue required to amortize the amounts outstanding by September 9, 2003. (ii) Interest on amounts outstanding accrues at prime plus 3% starting January 1, 2002, through September 30, 2002, and increases to prime plus 4% after October 1, 2002. We are required to pay interest only on the outstanding balance through December 31, 2002. (iii) The amount available under the agreement was increased by $2.5 million, making the total available $55.9 million. Aquila may, at its discretion, advance additional loans up to $2.5 million to be used for our development operations and/or working capital needs. (iv) A "change of control" provision was added, which calls for the prepayment of the entire outstanding balance, together with any accrued and unpaid interest, at the occurrence of a change of control of the Company. (v) We have the option to purchase from Aquila 490,000 shares of our common stock previously issued to Aquila for a price of $2.6 million if a sale of the Company is consummated prior to September 30, 2002. (vi) Aquila's one-time right to require us to purchase shares of our common stock previously issued to Aquila (the "Put Option") was amended to provide that Aquila has the option to sell to us up to 490,000 shares of our common stock at $10.00 per share if a sale of the Company is consummated at any time after September 30, 2002 and prior to September 9, 2003, or at $12.50 per share if the outstanding balance under the Aquila Credit Agreement is paid on the earlier of September 9, 2003 or the date on which Aquila notifies us of the acceleration of payment of the outstanding balance because of the occurrence of an event of default. (vii) We issued to Aquila 125,000 shares of the Company's common stock as a part of the amendment. If a sale of the Company is not consummated before October 1, 2002, we will issue Aquila an additional 150,000 shares. (viii) Upon a change of control of the Company occurring on or before September 30, 2002, we will pay Aquila $500,000. If a change of control of the Company occurs after September 30, 2002, we will pay Aquila $1,250,000. Through March 29, 2002, we had drawn $800,000 under provision (iii) above, and had $1.7 million available for future draws. The Aquila Credit Agreement is secured by substantially all of our oil and gas properties and contains various covenants and restrictions, including ones that could limit our ability to incur other debt, dispose of assets, or change management. Interest on the amounts outstanding under the Aquila Credit Agreement accrues at prime plus 2% and was added to the loan balance through March 31, 2001. The weighted average interest rate for borrowings outstanding under the Aquila Credit Agreement at December 31, 2001 was 7%. The outstanding loan balance is due in full on September 9, 2003. As part of the transaction, we also entered into an Agency Agreement with Aquila under which we pay Aquila a marketing fee equal to 1% of the net proceeds (as defined) from the sale of our oil and gas production to market our gas and to negotiate our gas purchase contracts. In September 1999, we also entered into a five year, $5.5 million master rental contract with Universal Compression, Inc. to refinance our East Blanco gas sweetening plant. The proceeds from that financing were used to repay a term loan from Bank One, Texas, N.A. that was secured by the plant. The master rental contract bears interest at an imputed rate of 12.8%. Payments under the master rental contract commenced in September 1999. We made principal payments totaling $439,000 and $384,000 to Universal Compression during 2001 and 2000, respectively. In July 1998, we negotiated an unsecured term loan for up to $205,000 with Bank One, Colorado, N.A. to finance the purchase of land and a building for our field office. We drew $155,000 on this loan during 1998. Principal and interest is payable quarterly beginning October 1, 1998. We repaid $16,000 and $15,000 of this loan during 2001 and 2000, respectively. In March 1999, the due date of the loan was extended from July 1999 to April 2002. In May 2001, the due date of the unsecured note payable was extended from April 2002 to July 2006, and the interest rate was reduced from 8.5% to 8% per annum. In April 2000, we redeemed 55,200 shares of our Series B Mandatorily Redeemable Convertible Preferred Stock at the mandatory redemption price of $10 per share by issuing a convertible promissory note for $552,000 to the Series B holder. Interest on the note accrued at 11.3% and was payable quarterly beginning on June 30, 2000. The note and all accrued interest was paid in full in October 2000. We redeemed the remaining 80,000 shares of Series B Preferred Stock in April 2001 at $10.00 per share. In April 2000, the Government of Costa Rica awarded us a concession to explore for oil and natural gas on approximately 2.3 million acres in the northeast quadrant of Costa Rica. We have completed an environmental assessment of our proposed operations, and are currently in the process of negotiating final concession contracts. Once we sign final contracts, the work program is expected to require the expenditure of $8.8 million (including the drilling of six wells) over a three-year period, with a possible extension of three more years. We will need to secure joint venture or other additional financing in order to complete the work program. Results of Operations
Year Ended December 31, 2001 2000 1999 (In thousands, except per unit data) Operating Results from Oil and Gas Operations: Oil and gas revenues $19,340 $16,803 $13,138 Production tax and marketing expense 3,655 3,422 1,682 Lease operating expense (2) 8,394 4,173 3,425 Depletion 6,476 5,570 4,319 Depreciation 300 258 268 Impairment 16,418 -- -- Net Production: Natural gas (MMcf) 5,954 6,022 5,600 Oil (MBbl) 105 171 172 Total (MMcfe) 6,584 7,048 6,632 Average Sales Price Realized (1): Natural gas (per Mcf) $ 2.83 $ 2.10 $ 1.81 Oil (per Bbl) $ 23.97 $ 24.43 $ 17.38 Per Mcfe $ 2.94 $ 2.38 $ 1.98 Average Cost Data (per Mcfe): Production tax and marketing expense $ 0.56 $ 0.49 $ 0.25 Lease operating expense (2) $ 1.27 $ 0.59 $ 0.52 Depletion $ 0.98 $ 0.79 $ 0.65
________________ (1) Includes effects of hedging. See "Hedging Activities." (2) Lease operating expense in 2001 includes assessments for possessory interest taxes, interest and penalties of $2.2 million for 1998-2000 and $1.1 million for 2001 which we are protesting. Year Ended December 31, 2001 Compared with Year Ended December 31, 2000 Revenues. Total revenues for the year ended December 31, 2001 increased 14% to $19,765,000 from $17,307,000 for the year ended December 31, 2000. Oil and gas sales for the year ended December 31, 2001 increased 15% to $19,340,000 from $16,803,000. The increase was due to higher gas prices, partially offset by oil and gas production declines. Average oil prices for the year ended December 31, 2001 decreased 2% to $23.97 per barrel from $24.43 per barrel for the year ended December 31, 2000 and average gas prices for the year ended December 31, 2001 increased 35% to $2.83 per Mcf from $2.10 per Mcf for the year ended December 31, 2000. Natural gas constituted approximately 90% of our production in 2001 and 85% in 2000. Oil production for the year ended December 31, 2001 decreased 39% to 105,000 barrels from 171,000 barrels for the year ended December 31, 2000 and gas production for the year ended December 31, 2001 decreased 1% to 5,954,000 Mcf from 6,022,000 Mcf for the year ended December 31, 2000. In September 2001, we sold our Delaware Basin properties, effective July 1, 2001. The sold properties produced primarily oil. Production Tax and Marketing. Production tax and marketing expenses increased 7% to $3,655,000 in 2001 from $3,422,000 in 2000. Production taxes are calculated and paid on prices before hedging gains or losses. As a percentage of sales before hedging gains or losses, production taxes and marketing expenses were 16% and 13% in 2001 and 2000, respectively. Production tax rates increased in 2001. In addition, the production tax rate for our Delaware Basin properties, which we sold in September 2001, averaged 9% of sales compared to our remaining properties in the San Juan Basin which averaged 18% of sales in 2001. Production tax and marketing expense per Mcfe increased $0.07 to $0.56, or 7%, in 2001 from $0.49 in 2000 because of higher gas prices. Lease Operating Expense. Lease operating expenses increased 101% to $8,394,000 in 2001 from $4,173,000 in 2000. In 2001, the Jicarilla Apache Nation assessed us possessory interest taxes, interest and penalties of approximately $2,200,000 for 1998-2000 and $1,100,000 for 2001. We paid the assessments under protest. These amounts are included in lease operating expense in 2001. Excluding the assessment, lease operating expense per Mcfe increased $0.18, or 31%, to $0.77 in 2001 from $0.59 in 2000 due to higher plant operation, salt water disposal and surface maintenance costs in 2001 relative to increases in production. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended December 31, 2001 increased 16% to $7,399,000 from $6,382,000 for the year ended December 31, 2000, primarily due to higher depletion expense. Depletion per Mcfe for the year ended December 31, 2001 increased 24% to $0.98 from $0.79 for the year ended December 31, 2000, primarily due to a higher ratio of increases in capital expenditures to increases in reserves. Impairment of Oil & Gas Properties. Under the full cost accounting rules of the Securities and Exchange Commission, we review the carrying value of our oil and gas properties each quarter on a country-by-country basis. Under full cost accounting rules, net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. Application of these rules generally requires pricing future production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and requires a write-down if the "ceiling" is exceeded, unless the prices recover subsequent to the balance sheet date but before the financial statements for the quarter are issued. If a smaller write-down is calculated using the subsequent pricing, then the smaller amount may be recorded. Using price increases subsequent to September 30, 2001, we recorded a charge in third quarter 2001 to write-down our oil and gas properties by $16,418,000. Had we used the prices in effect at September 30, 2001, the write-down would have been $25,292,000. We currently operate only in the continental United States. Loss on Sale of Oil and Gas Properties. On September 14, 2001, we completed the sale of our Delaware Basin oil and gas properties, effective July 1, 2001, for an adjusted purchase price of approximately $31,463,000. After paying approximately $2,033,000 of additional costs which included approximately $1,325,000 resulting from the settlement of our oil swap associated with the Delaware Basin properties, we received net proceeds of $29,430,000. Of those net proceeds, we used $24,134,000 to repay a portion of the note payable to Aquila (see Note 3 to our consolidated financial statements). We account for our oil and gas properties using the full cost method of accounting, under which sales of properties are generally treated as adjustments of capitalized costs and no gains or losses are recorded, unless they are significant. Our interests in the Delaware Basin properties constituted approximately 38% of our total reserve quantities at June 30, 2001. Because the sale significantly altered the relationship between our capitalized costs and our proved oil and gas reserves, we recognized a loss on the sale of oil and gas properties of $3,128,000 for the year ended December 31, 2001. The loss included costs from an allocation of our total undepleted full cost pool at June 30, 2001, between the properties sold and the properties retained, based on the relative estimated fair value of the properties sold and retained. Also included in the loss on the sale of oil and gas properties for 2001 is a net gain of $19,000 on other oil and gas equipment. General and Administrative Expenses. General and administrative expenses for the year ended December 31, 2001 increased 78% to $6,439,000 from $3,609,000 for the year ended December 31, 2000. The increase is primarily due to non-cash stock compensation expense, primarily related to the issuance of employee stock options with below market strike prices, which was higher in 2001 by approximately $1,924,000. In addition, unusual non-cash expenses in 2001 related to a termination settlement with one of our former officers and a partial forgiveness of certain notes receivable from related party shareholders totaled approximately $907,000. Interest and Other Expenses. Interest and other expenses for the year ended December 31, 2001 decreased 9% to $5,716,000 from $6,252,000 for the year ended December 31, 2000. The decrease is primarily due to lower outstanding borrowings and lower interest rates. Income Taxes. We incurred net operating losses for U.S. Federal income tax purposes in 2001 and 2000, which can be carried forward to offset future taxable income. Statement of Financial Accounting Standards No. 109 requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our oil and gas producing activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our decision to provide a valuation allowance equal to the net deferred tax asset. Accordingly, we did not recognize any tax benefit in our consolidated statements of operations for the years ended December 31, 2001 and 2000. At December 31, 2001, we had a net operating loss carryforward for U.S. Federal income tax purposes of $47,300,000, which will begin to expire in 2002. Net Loss. Net loss for the year ended December 31, 2001 increased to $31,365,000 from $6,531,000 for the year ended December 31, 2000 as a result of the factors discussed above. We paid the 8% dividend of $19,000 and $77,000 on $800,000 and $798,000 face amount Series B Mandatorily Redeemable Convertible Preferred Stock in each of the years ended December 31, 2001 and 2000, respectively, and realized accretion of $2,000 and $8,000, respectively. In 1999, we issued 420,000 shares of mandatorily redeemable common stock, in conjunction with a refinancing. In 2000, we issued an additional 70,000 shares of mandatorily redeemable common stock in conjunction with an amendment to the same financing agreement. The difference between the value of the shares at the redemption price of $12.50 per share and the market value of the shares at the date of issuance is being accreted over a period of up to 49 months. During 2001 and 2000, we realized accretion of $605,000 and $428,000, respectively, related to these shares. Net loss attributable to common shareholders for the year ended December 31, 2001 was $31,991,000 compared to net loss attributable to common shareholders of $7,044,000 for the year ended December 31, 2000. Year Ended December 31, 2000 Compared with Year Ended December 31, 1999 Revenues. Total revenues for the year ended December 31, 2000 increased 30% to $17,307,000 from $13,298,000 for the year ended December 31, 1999. Oil and gas sales for the year ended December 31, 2000 increased 28% to $16,803,000 from $13,138,000. The increase was due to higher oil and gas prices and higher gas production. Average oil prices for the year ended December 31, 2000 increased 41% to $24.43 per barrel from $17.38 per barrel for the year ended December 31, 1999 and average gas prices for the year ended December 31, 2000 increased 16% to $2.10 per Mcf from $1.81 per Mcf for the year ended December 31, 1999. Natural gas constituted approximately 85% of our production in 2000 and 84% in 1999. Oil production for the year ended December 31, 2000 decreased 1% to 171,000 barrels from 172,000 barrels for the year ended December 31, 1999 and gas production for the year ended December 31, 2000 increased 8% to 6,022,000 Mcf from 5,600,000 Mcf for the year ended December 31, 1999. Gas production for 2000 was up from 1999 because of the resumption of our drilling and recompletion program in fourth quarter 2000 after the receipt of additional financing. We have been focusing on drilling gas wells. Production Tax and Marketing. Production tax and marketing expenses for the year ended December 31, 2000 increased 103% to $3,422,000 from $1,682,000 for the year ended December 31, 1999. The increase was primarily attributable to higher prices in 2000. Production taxes are calculated and paid on prices before hedging gains or losses. As a percentage of sales before hedging losses, production tax and marketing expense was 13% in both 2000 and 1999. Production tax and marketing expense per Mcfe increased $0.24, or 96%, to $0.49 for the year ended December 31, 2000 from $0.25 for the year ended December 31, 1999. Lease Operating Expense. Lease operating expenses ("LOE") increased 22% to $4,173,000 in 2000 from $3,425,000 in 1999. LOE per Mcfe increased $0.07, or 13%, to $0.59 for the year ended December 31, 2000 from $0.52 for the year ended December 31, 1999. LOE per Mcfe in 2000 is higher primarily due to increased field personnel costs and possessory interest taxes relative to increases in production. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended December 31, 2000 increased 32% to $6,382,000 from $4,822,000 for the year ended December 31, 1999, primarily due to higher depletion expense. Depletion per Mcfe for the year ended December 31, 2000 increased 22% to $0.79 from $0.65 for the year ended December 31, 1999, primarily due to a higher ratio of increases in capital expenditures to increases in reserves. General and Administrative Expenses. General and administrative expenses for the year ended December 31, 2000 increased 24% to $3,609,000 from $2,915,000 for the year ended December 31, 1999. The increase is primarily due to the issuance of employee stock options with a below market strike price and increased costs for contract and consulting services. Interest and Other Expenses. Interest and other expenses for the year ended December 31, 2000 increased 100% to $6,252,000 from $3,126,000 for the year ended December 31, 1999. The increase is primarily due to higher outstanding borrowings and higher interest rates. Income Taxes. We incurred net operating losses for U.S. Federal income tax purposes in 2000 and 1999, which can be carried forward to offset future taxable income. Statement of Financial Accounting Standards No. 109 requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our oil and gas producing activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our decision to provide a valuation allowance equal to the net deferred tax asset. Accordingly, we did not recognize any tax benefit in our consolidated statements of operations for the years ended December 31, 2000 and 1999. At December 31, 2000, we had a net operating loss carryforward for U.S. Federal income tax purposes of $38,800,000, which will begin to expire in 2001. Extraordinary Loss. We incurred an extraordinary loss of $105,000 during the year ended December 31, 1999, as a result of the refinancing of our debt with a new lender. Net Loss. Net loss for the year ended December 31, 2000 increased 135% to $6,531,000 from $2,777,000 for the year ended December 31, 1999 as a result of the factors discussed above. We paid the 8% dividend of $77,000 and $108,000 on $798,000 and $1,341,000 face amount Series B Mandatorily Redeemable Convertible Preferred Stock in each of the years ended December 31, 2000 and 1999, respectively, and realized accretion of $8,000 and $12,000, respectively. In 1999, we issued 420,000 shares of mandatorily redeemable common stock, in conjunction with a refinancing. In 2000, we issued an additional 70,000 shares of mandatorily redeemable common stock in conjunction with an amendment to the same financing agreement. The difference between the value of the shares at the redemption price of $12.50 per share and the market value of the shares at the date of issuance is being accreted over a period of up to 49 months. During 2000 and 1999, we realized accretion of $428,000 and $116,000, respectively, related to these shares. Net loss attributable to common shareholders for the year ended December 31, 2000 was $7,044,000 compared to net loss attributable to common shareholders of $3,013,000 for the year ended December 31, 1999. Hedging Activities We use hedging instruments to manage commodity price risks. We have used energy swaps and other financial arrangements to hedge against the effects of fluctuations in the sales prices for oil and natural gas. Gains and losses on such transactions are matched to product sales and charged or credited to oil and gas sales when that product is sold. Management believes that the use of various hedging arrangements can be a prudent means of protecting our financial interests from the volatility of oil and gas prices. Under our credit agreement with Aquila, we may be required to maintain price hedging arrangements in place with respect to up to 65% of our oil and gas production upon terms satisfactory to us and Aquila. We recognized hedging losses of $3,292,000, $8,965,000 and $102,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Miscellaneous Our oil and gas operations are significantly affected by certain provisions of the Internal Revenue Code that are applicable to the oil and gas industry. Current law permits our intangible drilling and development costs to be deducted currently, or capitalized and amortized over a five year period. We, as an independent producer, are also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced (if such percentage depletion exceeds cost depletion). Generally, this deduction is 15% of gross income from an oil and gas property, without reference to the taxpayer's basis in the property. The percentage depletion deduction may not exceed 100% of the taxable income from a given property. Further, percentage depletion is limited in the aggregate to 65% of our taxable income. Any depletion disallowed under the 65% limitation, however, may be carried over indefinitely. Inflation has not historically had a material impact on our financial statements, and management does not believe that we will be materially more or less sensitive to the effects of inflation than other companies in the oil and gas industry. ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Commodity Price Risk We use commodity derivative financial instruments, including swaps, to reduce the effect of natural gas price volatility on a portion of our natural gas production. Commodity swap agreements are generally used to fix a price at the natural gas market location or to fix a price differential between the price of natural gas at Henry Hub and the price of gas at its market location. Settlements are based on the difference between a fixed and a variable price as specified in the agreement. The fair value of these instruments reflected below is the estimated amount that we would receive (or pay) to settle the contracts as of December 31, 2001. Actual settlement of these instruments when they mature will differ from these estimates reflected in the table. Gains or losses realized from these instruments hedging our production are expected to be offset by changes in the actual sales price received by us for our natural gas production. See "Hedging Activities" above. The following table summarizes our outstanding energy swaps at December 31, 2001:
Fixed Prie Year MMBtu per MMBtu Fair Value 2002 1,558,000 $2.55-$3.91 $ 94,000 2003 996,000 $2.55 (629,000) 2004 852,000 $2.55 (657,000)
Under our credit agreement with Aquila, we may be required to maintain price hedging arrangements in place with respect to up to 65% of our oil and gas production. Accordingly, included above are agreements to hedge a total of 3,406,000 MMBtu of gas related to production for 2002 -- 2004 at fixed prices ranging from $2.55-$3.91 per MMBtu. In addition to the amounts in the above table, we entered into basis swaps to fix the differential between the NYMEX (Henry Hub) price and the index price at which the hedged gas is to be sold for 3,406,000 MMBtu for 2002 -- 2004. At December 31, 2001, these basis swaps had a fair value of $135,000, $(65,000) and $(72,000) for production related to 2002, 2003 and 2004, respectively. Interest Rate Risk The table below provides information about our financial instruments sensitive to changes in interest rates, including debt obligations. The table presents principal cash flows and related weighted average interest rates by expected maturity dates.
Expected Maturity (In thousands) Fair 2002 2003 2004 2005 2006 Thereafter Value Long-term debt: Fixed rate $517 $ 586 $3,514 $17 $ 41 $ -- $ 4,675 Average interest rate 12.7% 12.7% 12.8% 8.0% 8.0% -- Variable rate $ -- $26,711 $ -- $ -- $ -- $ -- $26,711 Average interest rate -- 7.75% -- -- -- --
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our consolidated financial statements that constitute Item 8 follow the text of this Annual Report on Form 10-K. An index to the consolidated financial statements appears at page F-1. ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information concerning our directors and executive officers is set forth in Item 1 of Part I of this report. ITEM 11: EXECUTIVE COMPENSATION The following table summarizes certain information regarding compensation awarded to, earned by or paid by us for services rendered for the year ended December 31, 2001 to our chief executive officer and our four other most highly compensated individuals whose total compensation, exceeded $100,000 for such year. SUMMARY COMPENSATION TABLE
Annual Compensation Long Term Compensation Awards Name and Other Annual Restricted Securities All Other Principal Compensation Stock Awards Underlying Compensation Position Year Salary($) Bonus($) ($) ($) Options (#) ($) G.O. Mallon, Jr. 2001 190,000 165,434 -- -- 132,000 2,625 CEO 2000 175,000 46,320 -- -- 24,000 2,625 1999 175,000 29,530 -- -- -- 2,500 R.K. Ross 2001 155,000 68,513 -- -- 30,000 2,625 E.V.P. 2000 140,000 21,625 -- -- 9,384 2,625 1999 140,000 13,390 -- -- -- 2,500 P.H. Blum 2001 42,221 5,969 -- 2,910 97,500 1,187 E.V.P. A.R. Lopez 2001 97,050 51,779 -- 9,657 20,000 2,625 Treasurer 2000 97,050 14,924 -- -- 8,000 2,625 1999 92,400 9,465 -- -- -- 2,500 D.M. Erickson 2001 121,500 66,427 -- 18,026 50,000 2,625 Senior V.P. 2000 115,500 10,485 -- -- 8,000 2,625 of Mallon Oil 1999 110,000 8,295 -- -- -- 2,500
OPTION GRANTS IN 2001
Individual Grants Number of Securities Exercise or Grant Date Underlying Options Percent of Total Otions Base Price Expiration Present Value Name Granted (#) Granted in Fiscal Year ($/Sh) Date ($) (1) G.O. Mallon, Jr. 132,000 27.8% 0.01 12/31/10 842,160 R.K. Ross 30,000 6.3% 0.01 12/31/10 191,400 P.H. Blum 97,500 20.5% 0.01 12/31/10 622,050 A.R. Lopez 20,000 4.2% 0.01 12/31/10 127,600 D.M. Erickson 50,000 10.5% 0.01 12/31/10 319,000
1. The Grant Date Present Value of the options was determined using the Black- Scholes option-pricing model, using the following assumptions: risk-free interest rate - 4.6%; expected life in years - 6; expected volatility - 99%; expected dividends - 0.0%. The following table shows the number of shares covered by all exercisable and unexercisable stock options held by the named individuals as of December 31, 2001, as well as the value of unexercisable "in the money" options at that date. AGGREGATE OPTION EXERCISES IN 2000 AND YEAR END OPTION VALUES
Value Number of Securities Under- Value of Unexercised Shares Acquired Realized lying Unexercised Options In-The-Money Options Name On Exercise (#) ($) At December 31, 2001 (#) At December 31, 2001 ($)(1) Exercisable Unexercisable Exercisable Unexercisable G.O. Mallon, Jr. -- -- 47,491 132,000 122,665 397,320 R.K. Ross -- -- 75,560 33,128 38,395 99,715 P.H. Blum -- -- 49,402 98,833 118,600 247,487 A.R. Lopez 5,334 33,424 22,000 22,666 -- 8,025 D.M. Erickson -- -- 25,334 52,666 76,255 158,525
(1) Amounts shown represent aggregated fair market value at the share price on December 31, 2001 of $3.02 per share, less the aggregate exercise price of the unexercised "in the money" options held. These values have not been, and may never be, realized. Actual gains, if any, on exercise will depend on the value of the common stock on the date of exercise. Equity Participation Plans. Under the Mallon Resources Corporation 1988 Equity Participation Plan and the Mallon Resources Corporation 1997 Equity Participation Plan, shares of common stock have been reserved for issuance for various compensation purposes. The Plans are administered by the Compensation Committee, currently comprised of Messrs. Reinhardt and Douglass. The terms of any awards made under the Plans are within the broad discretion of the Committee. At December 31, 2001, the following options to purchase shares of our common stock were issued and outstanding under the Plans:
Weighted Number of Average Shares Exercise Price 764,055 $2.10
Employee Profit Sharing and Thrift Plan. We established the Mallon Resources Corporation 401(k) Profit Sharing Plan (the "401(k) Plan") effective January 1, 1989. We will match an employee's contribution to the 401(k) Plan in an amount up to 25% of his or her eligible monthly contributions. We may also contribute additional amounts at the discretion of the Compensation Committee of the Board of Directors, contingent upon our realization of earnings that, in the sole discretion of the Board of Directors, are adequate to justify a corporate contribution. The 401(k) Plan is open to all of our full time employees who have attained the age of 21. ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information concerning the beneficial ownership of shares of our common stock as of March 15, 2001, by (a) each shareholder known by us to own of record or beneficially more than 5% of our outstanding common stock; (b) our chief executive officer (Mr. Mallon); (c) each of our directors; and (d) all of our directors and executive officers as a group:
Number Percent Name and address (1) of shares Owned George O. Mallon, Jr. 693,024 (2) 6.27% Roy K. Ross 147,702 (3) 1.35% Peter H. Blum 110,735 (4) 1.01% Frank Douglass 66,010 (5) * Roger R. Mitchell 70,813 (6) * Francis J. Reinhardt, Jr. 77,586 (7) * Rutabaga Capital Management. 603,400 (8) 5.55% Wellington Management Company, LLP 720,000 (8) 6.63% Aquila Energy Capital 615,000 (8) 5.66% J O Hambro Capital Management Limited 1,578,200 (8) 14.52% All officers and directors as a group (7 persons) 1,224,438 (9) 10.58%
__________ * Less than 1% 1. The address of Messrs. Mallon, Ross, and Blum is 999 18th Street, Suite 1700, Denver, CO 80202. The address of Mr. Douglass is 10424 Woodford, Dallas, TX 75229. The address of Mr. Mitchell is 113 Cypress Cove Lane, Mooresville, NC 28117. The address of Mr. Reinhardt is 650 Madison Ave., 23rd Floor, New York, NY 10022. The address of Rutabaga Capital Management is 64 Broad Street, 3rd Floor, Boston, MA 02109. The address of Wellington Management Company, LLP is 75 State Street, Boston, MA 02109. The address of Aquila Energy Capital is 909 Fannin Street, Suite 1850, Houston, TX 77010-1007. The address of J O Hambro Capital Management Limited is Ryder Court, 14 Ryder Street, London SW1Y 6QB, England. 2. Includes 2,166 shares owned by Mr. Mallon's wife and 179,491 shares that could be acquired by Mr. Mallon upon the exercise of immediately exercisable stock options and warrants that he holds. 3. Includes 88,688 shares that could be acquired by Mr. Ross upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 20,000 shares covered by stock options that have not yet vested. 4. Includes 63,235 shares that could be acquired by Mr. Blum upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 85,000 shares covered by stock options and warrants that have not yet vested. 5. Includes 36,406 shares that could be acquired by Mr. Douglass upon the exercise of immediately exercisable stock options and warrants that he holds. 6. Includes 31,736 shares that could be acquired by Mr. Mitchell upon the exercise of immediately exercisable stock options that he holds. 7. Includes 34,401 shares that could be acquired by Mr. Reinhardt upon the exercise of immediately exercisable stock options and warrants that he holds. 8. Based upon information contained in various public filings made with the S.E.C. 9. Includes 465,290 shares that could be acquired upon the exercise of immediately exercisable stock options and warrants. Does not include 118,333 shares covered by stock options and warrants that have not yet vested. ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Under our "Stock Ownership Encouragement Program," in August 1999, Messrs. Mallon and Ross borrowed $1,585,018 and $391,284, respectively, from us that they used to exercise certain options owned by them. Messrs. Mallon and Ross issued promissory notes to us in the noted amounts, which bear interest at the rate of 7.0% per annum, and are due August 31, 2004. In June 2001, the amounts due under the notes were reduced to $230,548 and $56,914, respectively. Upon the occurrence of a change in control of the Company (as defined in our Bylaws), all amounts due under the notes will be automatically forgiven. In May 2001, we entered into an employment termination agreement with Kevin M. Fitzgerald, a former officer and director. Under the agreement, Mr. Fitzgerald waived certain portions of his employment contract, surrendered certain options and warrants and conveyed to us his interest in Deep Gas, LLC. In consideration of Mr. Fitzgerald's concessions, we accelerated the vesting of certain options held by Mr. Fitzgerald and reduced the amount of a note receivable from Mr. Fitzgerald. In July 1999, we entered into a financial consulting services contract with Bear Ridge Capital LLC., which is wholly-owned by Mr. Blum, one of our directors. Under the contract, Bear Ridge Capital LLC was paid a monthly retainer and was issued warrants to purchase an aggregate of 40,000 shares of our common stock at a per share exercise price of $0.01. Warrants covering 10,000 shares of our common stock vested on July 1, 2001. The remaining warrants were forfeited. During 2001, 2000 and 1999, we paid Bear Ridge Capital LLC $99,000, $121,000 and $110,000 in fees, respectively, and expensed $3,000, $26,000 and $25,000 in stock compensation expense, respectively, related to the warrants. In September 2001, we entered into an employment agreement with Mr. Blum, pursuant to which he became Executive Vice President of the Company. PART IV ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this report: (1) Financial Statements See the accompanying index to our consolidated financial statements at page F-1, which lists the documents that are filed as a part of this report. (3) Exhibits See the Exhibit Index that follows the signature page to this report and is incorporated herein by this reference. (b) Reports on Form 8-K: We filed the following Periodic Report on Form 8-K during the fourth quarter of 2001: Date of Report Item(s) Reported November 27, 2001 Item 5. "Other Events" - Explore Strategic Alternatives (c) Exhibits: See the Exhibit Index that follows the signature page to this report and is incorporated herein by this reference. 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. Mallon Resources Corporation Date: April 4, 2002 By: /s/ George O. Mallon, Jr. ____________________________ George O. Mallon, Jr. Principal Executive Officer Date: April 4, 2002 By: /s/ Alfonso R. Lopez ____________________________ Alfonso R. Lopez Principal Financial Officer Principal Accounting Officer 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 date indicated. Date: April 4, 2002 By: /s/ George O. Mallon, Jr. ____________________________ George O. Mallon, Jr. Director Date: April 4, 2002 By: /s/ Frank Douglass ____________________________ Frank Douglass Director Date: April 4, 2002 By: /s/ Roy K. Ross ____________________________ Roy K. Ross Director Date: April 4, 2002 By: /s/ Peter H. Blum ____________________________ Peter H. Blum Director EXHIBIT INDEX Exhibit Number Document Description Location * 3.01 Amended and Restated Articles of Incorporation of the Company (1) * 3.02 Bylaws of the Company (1) * 3.03 Statement of Designations--Series B Preferred Stock (2) * 3.04 Shareholder Rights Agreement (3) *10.01 Mallon Employee Bonus Pool (10) *10.02 Equity Participation Plan, amended November 2, 1990 (4) *10.03 Stock Compensation Plan for Outside Directors (5) *10.04 1997 Equity Participation Plan (6) *10.05 (Amended and Restated) Employment Contract with CEO (10) *10.07 (Amended and Restated) Employment Contract of Executive Vice President (10) *10.08 Employment Contract of Executive Vice President (11) *10.09 Severance and Sale Program (7) *10.10 Stock Ownership Encouragement Program (8) *10.11 Promissory Note and Stock Pledge of CEO (7) *10.13 Promissory Note and Stock Pledge of Executive Vice President (7) *10.14 Aquila Energy Capital Credit Agreement, dated as of September 9, 1999 (9) *10.15 Master Rental Contract with Universal Compression dated September 9, 1999 (9) *10.19 Letter Agreement dated February 2000 with George O. Mallon, Jr. (10) *10.20 Replacement Promissory Note of CEO (12) *10.21 Replacement Promissory Note of Executive Vice President (12) *21.01 Subsidiaries (4) 99 Letter to the S.E.C. regarding Arthur Andersen LLP # ____________________________ * These exhibits were filed in previous filings with the S.E.C. identified below. 1. Incorporated by reference from Mallon Resources Corporation Exhibits to Registration Statement on Form S-4 (S.E.C. File No. 33-23076) filed on August 15, 1988. 2. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 8-K dated August 24, 1995. 3. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 8-K dated April 22, 1997. 4. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 10-K for fiscal year ended December 31, 1990. 5. Incorporated by reference from Mallon Resources Corporation Exhibits to Registration Statement on Form S-8 (S.E.C. File No. 33-39635) filed on March 28, 1991. 6. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) definitive proxy statement for annual meeting of shareholders held June 6, 1997. 7. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 10-K for fiscal year ended December 31, 1999. 8. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 8-K dated July 19, 1999. 9. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 8-K dated September 9, 1999. 10. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 10-K for fiscal year ended December 31, 2000. 11. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 10-Q dated September 30, 2001. 12. Incorporated by reference from Mallon Resources Corporation (S.E.C. File No. 0-17267) Form 10-Q dated June 30, 2001. # Filed herewith. GLOSSARY OF CERTAIN INDUSTRY TERMS Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bcf. Billion cubic feet. Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. Development location. A location on which a development well can be drilled. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves. Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Estimated future net revenues. Revenues from production of oil and gas, net of all production-related taxes, lease operating expenses and capital costs. Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Gross acres. An acre in which a working interest is owned. Gross well. A well in which a working interest is owned. MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. Mcf. One thousand cubic feet. Mcfe. One thousand cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of crude oil or condensate. MMBbl. One million barrels of crude oil or other liquid hydrocarbons. MMBtu. One million Btus. MMcf. One million cubic feet. MMcfe. One million cubic feet of natural gas equivalent. Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells. PV-10 or present value of estimated future net revenues. Estimated future net revenues discounted by a factor of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, in accordance with guidelines promulgated by the S.E.C. Production costs. All costs necessary for the production and sale of oil and gas, including production and ad valorem taxes. Productive well. A well that is producing oil or gas or that is capable of production. Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves. 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. Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed. S.E.C. The United States Securities and Exchange Commission. Undeveloped acreage. Lease acreage 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 such acreage contains proved reserves. Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. Index to Consolidated Financial Statements Page Report of Independent Public Accountants F-2 Consolidated Balance Sheets F-3 Consolidated Statements of Operations F-4 Consolidated Statements of Shareholders' Equity F-5 Consolidated Statements of Cash Flows F-7 Notes to Consolidated Financial Statements F-8 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholders of Mallon Resources Corporation: We have audited the accompanying consolidated balance sheets of Mallon Resources Corporation (a Colorado corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 Mallon Resources Corporation and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Notes 1 and 11 to the consolidated financial statements, on January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activity. ARTHUR ANDERSEN LLP Denver, Colorado March 15, 2002 MALLON RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands, except share data) ASSETS
December 31, 2001 2000 Current assets: Cash and cash equivalents $ 1,943 $ 14,155 Accounts receivable: Oil and gas sales 714 3,460 Joint interest participants, net of allowance of $3 and $39, respectively 302 353 Other 1 19 Inventories 151 215 Derivative asset 229 -- Prepaid expenses 28 -- Other 10 123 Total current assets 3,378 18,325 Property and equipment: Oil and gas properties, full cost method 93,933 120,972 Natural gas processing plant 8,648 8,560 Other property and equipment 1,085 1,112 103,666 130,644 Less accumulated depreciation, depletion and amortization (70,414) (59,057) 33,252 71,587 Debt issuance costs, net 1,041 1,529 Other, net 300 269 Total Assets $ 37,971 $ 91,710 ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Trade accounts payable $ 2,153 $ 3,689 Undistributed revenue 612 2,045 Accrued taxes and expenses 42 35 Current portion of long-term debt 517 12,179 Total current liabilities 3,324 17,948 Long-term debt, net of unamortized discount of $1,899 and $2,813, respectively 28,970 40,180 Derivative liability 1,423 -- 30,393 40,180 Total liabilities 33,717 58,128 Commitments and contingencies (Note 4) Series B Mandatorily Redeemable Convertible Preferred Stock, $0.01 par value, 500,000 shares authorized, -0- and 80,000 shares issued and outstanding, respectively -- 798 Mandatorily Redeemable Common Stock, $0.01 par value, 490,000 shares authorized, issued and outstanding, mandatory redemption of $6,125 4,853 4,248 Shareholders' equity: Common Stock, $0.01 par value, 25,000,000 shares authorized, 10,252,827 and 10,115,093 shares issued and outstanding, respectively 103 101 Additional paid-in capital 93,012 92,456 Accumulated deficit (92,520) (61,155) Accumulated other comprehensive loss (1,194) -- Notes receivable from shareholders -- (2,866) Total shareholders' equity (599) 28,536 Total Liabilities and Shareholders' Equity $ 37,971 $ 91,710 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts)
For the Years Ended December 31, 2001 2000 1999 Revenues: Oil and gas sales $ 19,340 $16,803 $13,138 Interest and other 425 504 160 19,765 17,307 13,298 Costs and expenses: Oil and gas production 12,049 7,595 5,107 Depreciation, depletion and amortization 7,399 6,382 4,822 Impairment of oil and gas properties 16,418 -- -- Loss on sale of oil and gas properties 3,109 -- -- General and administrative, net 6,439 3,609 2,915 Interest and other 5,716 6,252 3,126 51,130 23,838 15,970 Loss before extraordinary item (31,365) (6,531) (2,672) Extraordinary loss on early retirement of debt -- -- (105) Net loss (31,365) (6,531) (2,777) Accretion of mandatorily redeemable common stock (605) (428) (116) Dividends and accretion on preferred stock (21) (85) (120) Net loss attributable to common shareholders $(31,991) $(7,044) $(3,013) ======== ======= ======= Basic loss per share: Loss attributable to common shareholders before extraordinary item $ (2.99) $ (0.83) $ (0.40) Extraordinary loss -- -- (0.01) Net loss attributable to common shareholders $ (2.99) $ (0.83) $ (0.41) ======== ======= ======= Basic weighted average common shares outstanding 10,686 8,525 7,283 ======== ======= =======
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (In thousands, except share amounts)
Balance, December 31, 1998 7,021,065 $ 70 $73,941 $(51,847) $ -- $ -- $ 22,164 Stock options granted -- -- 66 -- -- -- 66 Stock options exercised 392,235 4 2,673 -- -- (2,622) 55 Accrued interest receivable on notes from shareholders -- -- -- -- -- (61) (61) Warrants issued to director -- -- 25 -- -- -- 25 Extension of warrants' expiration date -- -- 217 -- -- -- 217 Accretion of mandatorily redeemable common stock -- -- (116) -- -- -- (116) Issuance of restricted common stock to officers -- -- 37 -- -- -- 37 Dividends on preferred stock -- -- (108) -- -- -- (108) Accretion of preferred stock -- -- (12) -- -- -- (12) Net loss -- -- -- (2,777) -- -- (2,777) Balance, December 31, 1999 7,413,300 74 76,723 (54,624) -- (2,683) 19,490 Stock options granted -- -- 761 -- -- -- 761 Stock options exercised 18,567 1 -- -- -- -- 1 Accrued interest receivable on notes from shareholders -- -- -- -- -- (183) (183) Warrants issued to director -- -- 31 -- -- -- 31 Exercise of warrants 8,426 -- 67 -- -- -- 67 Accretion of mandatorily redeemable common stock -- -- (428) -- -- -- (428) Issuance of restricted common stock to officers -- -- 7 -- -- -- 7 Issuance of common stock to officers and directors in exchange for oil and gas properties 14,800 -- 119 -- -- -- 119 Issuance of common stock in public offering 2,660,000 26 15,261 -- -- -- 15,287 Dividends on preferred stock -- -- (77) -- -- -- (77) Accretion of preferred stock -- -- (8) -- -- -- (8) Net loss -- -- -- (6,531) -- -- (6,531) Balance, December 31, 2000 10,115,093 $101 $92,456 $(61,155) $ -- $(2,866) $28,536
(Continued) The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (In thousands, except share amounts) (Continued)
Balance, December 31, 2000 10,115,093 $101 $92,456 $(61,155) $ -- $(2,866) $ 28,536 $ -- Stock options granted -- -- 2,711 -- -- -- 2,711 Stock options exercised 94,734 2 -- -- -- -- 2 Warrants issued to director -- -- 3 -- -- -- 3 Cancellation of warrants in exchange for common stock 18,000 -- 3 -- -- -- 3 Issuance of restricted stock 25,000 -- 161 -- -- -- 161 Accretion of manda- torily redeemable common stock -- -- (605) -- -- -- (605) Dividends on preferred stock -- -- (19) -- -- -- (19) Accretion of preferred stock -- -- (2) -- -- -- (2) Interest on notes receivable from shareholders -- -- -- -- -- (87) (87) Payment of notes receivable from shareholder -- -- -- -- -- 360 360 Partial forgiveness of note receivable from shareholders -- -- (1,696) -- -- 2,593 897 Cumulative effect of change in accounting principle -- -- -- -- (15,171) -- (15,171) (15,171) Reclassification adjustment for settled hedging contracts -- -- -- -- 3,292 -- 3,292 3,292 Changes in fair value of outstand- ing hedge positions -- -- -- -- 10,685 -- 10,685 10,685 Net loss -- -- -- (31,365) -- -- (31,365) (31,365) Balance, December 31, 2001 10,252,827 $103 $93,012 $(92,520) $(1,194) $ -- $ (599) $(32,559) ========== ==== ======= ======== ======= ====== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
For the Years Ended December 31, 2001 2000 1999 Cash flows from operating activities: Net loss $(31,365) $ (6,531) $ (2,777) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 7,399 6,382 4,822 Impairment of oil and gas properties 16,418 -- -- Loss on sale of oil and gas properties 3,109 -- -- Accrued interest expense added to long-term debt 1,401 4,738 998 Accrued interest income added to notes receivable from shareholders (87) (183) (60) Extraordinary loss -- -- 105 Non-cash stock compensation expense 2,502 578 323 Amortization of discount on long-term debt 914 705 188 Partial forgiveness of notes receivable from related party shareholders 907 -- -- Changes in operating assets and liabilities: Decrease (increase) in: Accounts receivable 2,815 (1,535) (540) Inventory and other current assets 59 (48) (22) (Decrease) increase in: Trade accounts payable and undistributed revenue (2,969) (83) 408 Accrued taxes and expenses 6 (17) (97) Deferred revenue -- -- (910) Net cash provided by operating activities 1,109 4,006 2,438 Cash flows from investing activities: Additions to property and equipment (16,785) (17,818) (9,826) Proceeds from sale of property and equipment 29,465 -- -- Receipts from notes receivable-related parties 7 77 5 Net cash provided by (used in) investing activities 12,687 (17,741) (9,821) Cash flows from financing activities: Proceeds from long-term debt 837 12,414 43,332 Payments of long-term debt (26,025) (399) (34,404) Redemption of preferred stock (800) -- -- Debt issuance costs (3) (81) (1,995) Net proceeds from sale of common stock in public offering -- 15,287 -- Payment of preferred dividends (19) (77) (108) Payment of current note payable for redemption of preferred stock -- (552) -- Proceeds from stock option and warrant exercises 2 68 55 Net cash (used in) provided by financing activities (26,008) 26,660 6,880 Net (decrease) increase in cash and cash equivalents (12,212) 12,925 (503) Cash and cash equivalents, beginning of year 14,155 1,230 1,733 Cash and cash equivalents, end of year $ 1,943 $ 14,155 $ 1,230 ======== ======== ======== Supplemental cash flow information: Cash paid for interest $ 4,801 $ 773 $ 1,988 ======== ======== ======== Non-cash transactions: Issuance of common stock in exchange for oil and gas properties purchased from officers and directors $ -- $ 119 $ -- Sale of common stock in exchange for notes receivable from shareholders -- -- 2,622
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Nature of Operations: Mallon Resources Corporation ("Mallon" or the "Company") was incorporated on July 18, 1988 under the laws of the State of Colorado. The Company engages in oil and gas exploration and production through its wholly-owned subsidiary, Mallon Oil Company ("Mallon Oil"), whose oil and gas operations are conducted primarily in the State of New Mexico. Mallon operates its business and reports its operations as one business segment. Current Operating Issues: The Company has generated net losses of $31.4 million, $6.5 million and $2.8 million for the years ended December 31, 2001, 2000 and 1999, respectively. However, the Company has generated cash flows from operating activities of $1.1 million, $4.0 million and $2.4 million for the years ended December 31, 2001, 2000 and 1999, respectively. As discussed more fully in Note 2, on September 14, 2001, the Company completed the sale of its Delaware Basin oil and gas properties. Consequently, the Company's remaining operations are located primarily in the San Juan Basin of northwest New Mexico. The Company has minimal access to the capital necessary to continue to develop its properties in the San Juan Basin. Subsequent to year end, however, the Company was able to amend its credit facility to provide, among other things, for a $2.5 million increase in the borrowings available under the credit facility. In addition, the Company is currently seeking alternate methods of financing its discretionary capital expenditures for 2002, including joint ventures with industry partners. However, the Company can not be assured that it will be able to secure financing on terms acceptable to the Company. In addition, because production from the San Juan Basin is predominantly natural gas, the Company is particularly sensitive to changes in the price of natural gas. Historically, natural gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in natural gas prices received could have a significant impact on the Company's future results. If natural gas prices decline significantly from those received by the Company at year end, or if the Company is unable to maintain production levels at its San Juan Basin properties, Mallon may have to implement cost cutting measures in both its administrative and operating areas. As discussed more fully in Note 17, in conjunction with the February 2002 amendment to the Company's credit agreement, through December 31, 2002, the Company is only required to make interest payments on the credit facility. Management believes that cash on hand, availability under its credit facility and cash generated from operating activities will be sufficient to meet the Company's cash requirements through December 31, 2002. Principles of Consolidation: The consolidated financial statements include the accounts of Mallon Oil and all of its wholly-owned subsidiaries. All significant intercompany transactions and accounts have been eliminated from the consolidated financial statements. Cash, Cash Equivalents and Short-term Investments: Cash and cash equivalents include investments that are readily convertible into cash and have an original maturity of three months or less. All short- term investments are held to maturity and are reported at cost. Fair Value of Financial Instruments: The Company's financial instruments consist of cash, cash equivalents, accounts receivable, notes receivable, inventories, accounts payable, other accrued liabilities and long-term debt. Except for long-term debt, the carrying amounts of such financial instruments approximate fair value due to their short maturities. At December 31, 2001 and 2000, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount. The Company's derivative instruments, which are intended to manage commodity price risks, are recorded at fair value (see Note 11). Inventories: Inventories, which consist of oil and gas lease and well equipment, are valued at the lower of average cost or estimated net realizable value. Oil and Gas Properties: Oil and gas properties are accounted for using the full cost method of accounting. Under this method, all costs associated with property acquisition, exploration and development are capitalized, including general and administrative expenses directly related to these activities. All such costs are accumulated in one cost center, the continental United States. Proceeds on disposal of properties are ordinarily accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustment would significantly alter the relationship between capitalized costs and proved oil and gas reserves (see Note 2). Net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects (see Note 2). Depletion is calculated using the units-of-production method based upon the ratio of current period production to estimated proved oil and gas reserves expressed in physical units, with oil and gas converted to a common unit of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas (see Note 2). Estimated abandonment costs (including plugging, site restoration, and dismantlement expenditures) are accrued if such costs exceed estimated salvage values, as determined using current market values and other information. Abandonment costs are estimated based primarily on environmental and regulatory requirements in effect from time to time. At December 31, 2001 and 2000, in management's opinion, the estimated salvage values equaled or exceeded estimated abandonment costs. Other Property and Equipment: Other property and equipment is recorded at cost and depreciated over the estimated useful lives (generally three to seven years) using the straight- line method. Costs incurred relating to a natural gas processing plant are being depreciated over twenty-five years using the straight-line method. The cost of normal maintenance and repairs is charged to expense as incurred. Significant expenditures that increase the life of an asset are capitalized and depreciated over the estimated useful life of the asset. Upon retirement or disposition of assets, related gains or losses are reflected in operations. Gas Balancing: The Company uses the entitlements method of accounting for recording natural gas sales revenues. Under this method, revenue is recorded based on the Company's net working interest in field production. Deliveries of natural gas in excess of the Company's working interest are recorded as liabilities while under-deliveries are recorded as receivables. The receivables and liabilities at December 31, 2001 and 2000 are not material. Concentration of Credit Risk: As an operator of jointly owned oil and gas properties, the Company sells oil and gas production to numerous oil and gas purchasers and pays vendors for oil and gas services. The risk of non-payment by the purchasers is considered minimal and the Company does not generally obtain collateral for sales to them. Joint interest receivables are subject to collection under the terms of operating agreements which provide lien rights, and the Company considers the risk of loss likewise to be minimal. The Company is exposed to credit losses in the event of non-performance by counterparties to financial instruments, but does not expect any counterparties to fail to meet their obligations. The Company generally does not obtain collateral or other security to support financial instruments subject to credit risk but does monitor the credit standing of counterparties. Stock-Based Compensation: As permitted under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation", the Company has elected to continue to measure compensation cost using the intrinsic value based method of accounting prescribed by the Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees." The Company has made pro forma disclosures of net income (loss) and net income (loss) per share as if the fair value based method of accounting as defined in SFAS No. 123 had been applied (see Note 9). In March 2000, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 44, "Accounting for Certain Transactions Involving Stock Compensation." Adoption of this Interpretation did not have a material impact on the Company's financial position or results of operations. Transportation Costs: In September 2000, the Emerging Issues Task Force reached consensus on Issue No. 00-10, "Accounting for Shipping and Handling Fees and Costs" ("EITF Issue 00-10"). EITF Issue 00-10 requires retroactive restatement of transportation costs as an expense rather than as a reduction to revenue in certain cases. The implementation of EITF Issue 00-10 in the fourth quarter of 2000 had no impact on the Company's financial statements. General and Administrative Expenses: General and administrative expenses are reported net of amounts allocated to working interest owners of the oil and gas properties operated by the Company, and net of amounts capitalized pursuant to the full cost method of accounting. Hedging Activities: The Company's use of derivative financial instruments is limited to management of commodity price and interest rate risks. Gains and losses on such transactions are accounted for as part of the transaction being hedged. If an instrument is settled early, any gains or losses are deferred and recognized as part of the transaction being hedged (see Note 11). The information presented in Note 11 of the consolidated financial statements represents all of the Company's derivative financial instruments outstanding as of December 31, 2001, as defined by SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." In connection with adoption of SFAS No. 133 on January 1, 2001, the Company designated and documented the hedging relationship of the Company's derivative contracts in place at December 31, 2000 to hedge natural gas and oil sales. Upon adoption of SFAS No. 133 on January 1, 2001 the Company recorded as a cumulative effect of a change in accounting principle, a $15.2 million hedging loss in accumulated other comprehensive loss for the fair market value of derivative contracts designated as hedges, and a corresponding $15.2 million derivative liability. Comprehensive Income: The Company follows SFAS No. 130, "Reporting Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The Company recorded other comprehensive loss for the first time in the first quarter of 2001 when it adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (see Note 11). Per Share Data: Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if the Company's outstanding stock options and warrants were exercised (calculated using the treasury stock method) or if the Company's Series B Convertible Preferred Stock were converted to common stock. The consolidated statements of operations for 2001, 2000 and 1999 reflect only basic earnings per share because the Company was in a loss position for all years presented and all common stock equivalents are anti-dilutive. Use of Estimates and Significant Risks: The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make significant estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. The more significant areas requiring the use of estimates relate to oil and gas reserves, fair value of financial instruments, valuation allowance for deferred tax assets, and useful lives for purposes of calculating depreciation, depletion and amortization. Actual results could differ from those estimates. The Company and its operations are subject to numerous risks and uncertainties. Among these are risks related to the oil and gas business (including operating risks and hazards and the regulations imposed thereon), risks and uncertainties related to the volatility of the prices of oil and gas, uncertainties related to the estimation of reserves of oil and gas and the value of such reserves, the effects of competition and extensive environmental regulation, and many other factors, many of which are necessarily out of the Company's control. The nature of oil and gas drilling operations is such that the expenditure of substantial drilling and completion costs are required well in advance of the receipt of revenues from the production developed by the operations. Thus, it will require more than several quarters for the financial success of that strategy to be demonstrated. Drilling activities are subject to numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. Reclassifications: Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the presentation used in 2001. Recently Issued Accounting Pronouncements: In June 2001, the FASB issued SFAS No. 141, "Business Combinations," which addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001 and for all business combinations accounted for under the purchase method initiated before but completed after June 30, 2001. The adoption of SFAS No. 141 is not expected to have a material impact on the Company's financial position or results of operations. In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which addresses financial accounting and reporting for goodwill and other intangible assets. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001, and applies to all goodwill and other intangibles recognized in the financial statements at that date. The adoption of SFAS No. 142 is not expected to have a material impact on the Company's financial position or results of operations. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company will adopt SFAS No. 143 on January 1, 2003, but has not yet quantified the effects of adopting SFAS No. 143 on its financial position or results of operations. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to be Disposed Of." SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company will adopt SFAS No. 144 on January 1, 2002, but has not yet quantified the effects of adopting SFAS No. 144 on its financial position or results of operations. NOTE 2. OIL AND GAS PROPERTIES On September 14, 2001, the Company completed the sale of its Delaware Basin oil and gas properties, effective July 1, 2001, for an adjusted purchase price of approximately $31.5 million. After paying approximately $2.0 million of additional costs, which included approximately $1.3 million resulting from the early settlement of the Company's oil swap associated with the Delaware Basin properties, the Company received net proceeds of $29.4 million. Of those net proceeds, the Company used $24.1 million to repay a portion of the note payable to Aquila Energy Capital Corporation ("Aquila") (see Note 3). The Company accounts for its oil and gas properties using the full cost method of accounting, under which sales of properties are generally treated as adjustments of capitalized costs and no gains or losses are recorded, unless they are significant. The Company's interests in the Delaware Basin properties constituted approximately 38% of the Company's total reserve quantities at June 30, 2001. Because the sale significantly altered the relationship between the Company's capitalized costs and its proved oil and gas reserves, the Company recognized a loss on the sale of oil and gas properties of $3.1 million for the year ended December 31, 2001. The loss included costs from an allocation of the Company's total undepleted full cost pool at June 30, 2001, between the properties sold and the properties retained, based on the relative estimated fair value of the properties sold and retained. Under the full cost accounting rules of the Securities and Exchange Commission, the Company reviews the carrying value of its oil and gas properties each quarter on a country-by-country basis. Under full cost accounting rules, net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. Application of these rules generally requires pricing future production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and requires a write-down if the "ceiling" is exceeded, unless the prices recover subsequent to the balance sheet date but before the financial statements for the quarter are issued. If a smaller write-down is calculated using the subsequent pricing, then the smaller amount may be recorded. Using price increases subsequent to September 30, 2001, the Company recorded a charge in third quarter 2001 to write-down its oil and gas properties by $16.4 million. Had the Company used the prices in effect at September 30, 2001, the write-down would have been $25.3 million. In April 2000, the Government of Costa Rica awarded the Company a concession to explore for oil and natural gas on approximately 2.3 million acres in the northeast quadrant of Costa Rica. The Company has completed an environmental assessment of its proposed operations, and is currently in the process of negotiating final concession contracts. Once the Company signs final contracts, the work program is expected to require the expenditure of approximately $8.8 million (including the drilling of six wells) over a three- year period, with a possible extension of three more years. In June 2000, the Company purchased additional working interests in certain wells from two of the Company's officers and one of its directors in exchange for forgiveness of $56,000 of joint interest participants accounts receivable, 14,800 shares of common stock valued at $119,000 and $3,000 in cash. NOTE 3. NOTES PAYABLE AND LONG-TERM DEBT Long-term debt consists of the following:
December 31, 2001 2000 (In thousands) Note payable to Aquila Energy Capital Corporation, due 2003 $26,711 $ 50,042 Less unamortized discount (1,899) (2,813) 24,812 47,229 Lease obligation to Universal Compression, Inc. 4,567 5,006 8.0% unsecured note payable to Bank One, Colorado, N.A., due 2006 108 124 29,487 52,359 Less current portion (517) (12,179) Total $28,970 $ 40,180 ======= ========
The Company had a revolving line of credit (the "Bank One Facility") with Bank One, Texas, N.A. The Bank One Facility consisted of two separate lines of credit: a primary revolving line of credit and a term loan commitment of $6.5 million (the "Equipment Loan"). The Bank One Facility was retired in September 1999 (see discussion below). Unamortized loan origination fees of $105,000 related to the Bank One Facility are included in extraordinary loss on early retirement of debt in the Company's consolidated statement of operations for 1999. In September 1999, the Company established a credit agreement (the "Aquila Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"). Through December 31, 2001, the Company had drawn $52.3 million, including accrued interest and repaid $25.6 million under the Aquila Credit Agreement. Approximately $24.1 million was repaid with the proceeds from the sale of the Company's Delaware Basin properties in September 2001 (see Note 2). The initial amount available under the Aquila Credit Agreement was $45.7 million. In November 2000, the Aquila Credit Agreement was amended and the amount available under the agreement was increased by $7.7 million, making the total available $53.4 million. Through December 31, 2001, the Company had drawn $52.3 million, including accrued interest, under the Aquila Credit Agreement, of which $28.0 million was used to retire the Bank One Facility in September 1999. Principal payments on the four-year loan began in November 1999 based on the Company's cash flow from operations, as defined (the "Defined Cash Flow"), less advances for the Company's development drilling program. Through December 31, 2000, the Company did not make any principal payments because drilling expenditures equaled or surpassed Defined Cash Flow during that period. The Company had expected to begin making principal payments in March 2001 in amounts equal to the Defined Cash Flow and paid Aquila $1.4 million on April 6, 2001. On March 30, 2001, the Company negotiated a change in the terms of its agreement with Aquila to delay the required repayment of principal. Instead, the repayment schedule for the twelve months beginning April 30, 2001 was to be as follows: (i) for the months April 2001 to September 2001, the Company paid interest only, or approximately $2.2 million, and (ii) from October 2001 to March 2002, the Company was to make monthly principal and interest payments of $700,000 or a total of $4.2 million. Aquila allowed the Company to make interest only payments totaling $505,000 for October 2001 to December 2001. In February 2002, the Aquila Credit Agreement was amended for a second time to allow, among other things, for the payment of interest only on the outstanding balance through December 31, 2002 (see Note 17). The Aquila Credit Agreement is secured by substantially all of the Company's oil and gas properties and contains various covenants and restrictions, including ones that could limit the Company's ability to incur other debt, dispose of assets, or change management. Interest on the amounts outstanding under the Aquila Credit Agreement accrues at prime plus 2% and was added to the loan balance through March 31, 2001. The weighted average interest rate for borrowings outstanding under the Aquila Credit Agreement at December 31, 2001 was 7%. The outstanding loan balance is due in full on September 9, 2003. As part of the transaction, the Company also entered into an Agency Agreement with Aquila under which the Company pays Aquila a marketing fee equal to 1% of the net proceeds (as defined) from the sale of the Company's oil and gas production to market the Company's gas and to negotiate the Company's gas purchase contracts. Marketing fees of $133,000, $119,000 and $31,000 were recorded as oil and gas production expense in 2001, 2000 and 1999, respectively. The Company paid approximately $2.0 million in debt issue costs in connection with the establishment of the Aquila Credit Agreement. These costs are reflected, net of amortization, in the Company's December 31, 2001 and 2000 consolidated balance sheets, as debt issuance costs. The costs are being amortized over a period of up to 48 months using the effective interest rate method. Amortization expense, related to these costs, of $489,000, $439,000 and $109,000 is included in the Company's 2001, 2000 and 1999 consolidated statements of operations, respectively. In conjunction with the establishment and subsequent first amendment of the Aquila Credit Agreement, the Company issued to Aquila 490,000 shares of the Company's common stock (see Note 6). See Note 17 for additional stock issued in 2002. In September 1999, the Company also entered into a sale-leaseback agreement with Universal Compression, Inc. to refinance and retire the Equipment Loan under the Bank One Facility. The Company also terminated its interest rate swap agreement related to the Equipment Loan in September 1999 for a gain of $3,500. The sale-leaseback was recorded as a financing under the provisions of SFAS No. 98, "Accounting for Leases." The $5.5 million obligation has a five-year term with monthly payments beginning in September 1999. The Company made principal payments totaling $439,000 and $384,000 to Universal Compression during 2001 and 2000, respectively. The obligation bears interest at an imputed interest rate of 12.8%. In July 1998, the Company negotiated an unsecured term loan for up to $205,000 with Bank One, Colorado, N.A. to finance the purchase of land and a building for the Company's field office. The Company drew $155,000 on this loan during 1998. Principal and interest is payable quarterly. The Company repaid $16,000 and $15,000 of this loan during 2001 and 2000, respectively. In May 2001, the due date of the unsecured note payable was extended from April 2002 to July 2006, and the interest rate was reduced from 8.5% to 8% per annum. Estimated principal payments on outstanding debt at December 31, 2001 are as follows:
(In thousands) 2002 $ 517 2003 27,297 2004 3,514 2005 17 2006 41 Thereafter -- $31,386 =======
NOTE 4. COMMITMENTS AND CONTINGENCIES Operating Leases: The Company leases office space, office equipment and vehicles under non- cancelable leases which expire in 2003. Rental expense is recognized on a straight-line basis over the terms of the leases. The total minimum rental commitments at December 31, 2001 are as follows:
(In thousands) 2002 $238 2003 45 2004 20 Thereafter -- $303 ====
Rent expense was $337,000, $373,000 and $305,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Contingencies: As of December 31, 2001, the Revenue and Taxation Department of the Jicarilla Apache Nation (the "Nation") issued to the Company Possessory Interest Tax assessments for 1998, 1999, 2000 and 2001 totaling $3.5 million, including related penalties and interest. The Company has paid the assessments under protest. This amount is included in the Company's December 31, 2001 consolidated balance sheet under prepaid expenses. The Company has filed protests with the Nation taking the position that, among other things, certain rules and regulations promulgated in December 2000 by the Nation do not apply to the determination of Possessory Interest Tax for years prior to 2001. The first protest covering approximately $1.6 million for the periods prior to 2001 was denied in July 2001. The Company has filed an appeal. In October and November 2001, two additional protests covering $850,000 were denied. The Company intends to file appeals relating to the denial of these two protests. In connection with the decisions relating to the denial of these two protests, the Department recalculated the late payment charges in the original assessments and has refunded $168,000, including interest, to the Company. In March 2002, the Company was assessed an additional $1.5 million for 2002. The Company intends to file a protest for this amount also. The Company has: 1) requested that the Legislative Council of the Nation grant the Company relief, and 2) engaged New Mexico counsel to represent it. The final outcome of this matter cannot yet be predicted. By letter dated October 9, 2001, the Company was advised that the Minerals Management Service will audit the royalties payable on production from certain oil and gas properties in which the Company owns an interest. The audit began in mid-November 2001. The final outcome of this matter cannot yet be predicted. In June 2001, in connection with staff cuts that were part of general corporate reductions, the Company terminated an employee. The employee filed a complaint, in which he claims he was wrongfully terminated. The Company believes the allegations of the suit are wholly without merit, and intends to defend itself vigorously, but cannot predict the outcome of the case. In December 1998, Del Mar Drilling Company ("Plaintiff") filed a civil action against Mallon Oil. Plaintiff sought damages for an alleged breach of contract in the amount of $348,100, plus interest, costs and attorney's fees. In March 2001, the Company settled with the Plaintiff by paying the Plaintiff $50,000 in cash, and conveying to the Plaintiff certain used drilling materials having an estimated salvage value of $14,000. In 1992, the Minerals Management Service commenced an audit of royalties payable on production from certain oil and gas properties in which the Company owns an interest. The audit was initiated against the predecessor operator of the properties, but the Company has since undertaken primary responsibility for resolving matters that arise out of the audit. The Company's liability with respect to the predecessor operator's liability is limited to $100,000. However, the Company may have an additional liability with respect to transactions that have occurred subsequent to its purchase of the oil and gas properties in question. The audit focused on several matters, the most significant of which were the manner in which production is measured and the manner in which royalties are calculated and accounted for. Certain alleged deficiencies preliminarily suggested by the audit were contested. Determinations contrary to several of the Company's positions were rendered in June 1999, which the Company has determined not to appeal. Certain key items relating to the calculation of royalties have yet to be determined. A determination contrary to the Company's position concerning so-called "major portion" issues was recently rendered by the Department of the Interior. The Company's interests in this controversy are represented by outside legal counsel who is appealing the Department of the Interior's rulings. In addition, the Company has recently determined to attempt to negotiate a private protocol addressing the manner in which royalties are calculated and accounted for. The final outcome of these matters cannot yet be predicted. NOTE 5. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK In April 1994, the Company completed the private placement of 400,000 shares of Series B Mandatorily Redeemable Convertible Preferred Stock, $0.01 par value per share (the "Series B Stock"). The Series B Stock bore an 8% dividend payable quarterly, and was convertible into shares of the Company's common stock at an adjusted conversion price. Proceeds from the placement were $3,774,000, net of stock issue costs of $226,000. In connection with the Series B Stock, dividends of $19,000, $77,000 and $108,000 were paid in 2001, 2000 and 1999, respectively. Accretion of preferred stock issue costs was $2,000, $8,000 and $12,000 in 2001, 2000 and 1999, respectively. In April 2000, the Company redeemed 55,200 shares of its Series B Stock at the mandatory redemption price of $10 per share by issuing a convertible promissory note for $552,000 to the Series B holder, a company in which one of Mallon's directors is also a director. Interest on the note accrued at 11.3% and was payable quarterly beginning on June 30, 2000. The note and all accrued interest was paid in full in October 2000. The Company redeemed the remaining 80,000 shares of Series B Stock in April 2001 at the mandatory redemption price of $10.00 per share. NOTE 6. MANDATORILY REDEEMABLE COMMON STOCK In September 1999, in conjunction with the establishment of the Aquila Credit Agreement, the Company issued to Aquila 420,000 shares of the Company's common stock. In November 2000, in conjunction with an amendment to the Aquila Credit Agreement, the Company issued an additional 70,000 shares to Aquila. These transactions were recorded as Mandatorily Redeemable Common Stock in the accompanying consolidated balance sheets, based on the market value of the Company's common stock on the date of issuance. Aquila has a one-time right to require the Company to purchase the 490,000 shares at $12.50 per share during the 30-day period beginning September 9, 2003. The difference between the value of the shares at the redemption price of $12.50 per share and the market value of the shares on the date of issuance is being accreted to the redemption date using the effective interest method. Accretion of $605,000, $428,000 and $116,000 was recorded during the years ended December 31, 2001, 2000 and 1999, respectively, as a direct charge to additional paid-in capital and was included in the net loss attributable to common shareholders in the Company's consolidated statements of operations for 2001, 2000 and 1999. NOTE 7. CAPITAL Preferred Stock: The Board of Directors is authorized to issue up to 10,000,000 shares of preferred stock having a par value of $.01 per share, to establish the number of shares to be included in each series, and to fix the designation, rights, preferences and limitations of the shares of each series. At December 31, 2001 and 2000, -0- and 80,000 shares of Series B Preferred Stock were outstanding, respectively. Common Stock: In October 2000, the Company issued 2,660,000 shares of its common stock in a public offering at a price of $6.25 per share. The Company received net proceeds, after commissions and other costs, of approximately $15.3 million, which was used primarily to finance the Company's oil and gas drilling activities. Warrants: The Company has outstanding warrants to purchase an aggregate of 85,334 shares of common stock, as described below. In July 1999, the Company entered into a financial consulting services contract with Bear Ridge Capital LLC. Under the contract, Bear Ridge Capital was paid a monthly retainer and was issued warrants to purchase an aggregate of 40,000 shares of the Company's common stock at a per share exercise price of $0.01. Warrants covering 10,000 shares vested on July 1, 2001. The remaining warrants were forfeited. During 2001, 2000 and 1999, the Company recorded $3,000, $26,000 and $25,000, respectively, of stock compensation expense related to these warrants. Bear Ridge Capital is wholly-owned by a Company director and officer. Warrants to purchase an aggregate of 78,023 shares of the Company's common stock at an adjusted exercise price of $8.01 per share were issued in June 1995 to the holders of Laguna Gold Company's Series A Preferred Stock in connection with the private placement of that stock. In June 2000, warrants to purchase 8,426 shares were exercised for total proceeds of $67,500. The remaining 69,597 warrants expired June 30, 2000. In October 1998, several members of the Company's Board of Directors purchased from a third party 40,000 (of 160,000) warrants with an exercise price of $7.80 per share issued by the Company in October 1996. On December 11, 1998, the exercise price of all 160,000 outstanding warrants was reduced to $6.88 per share, the closing price of the Company's stock on that day. The repricing of the warrants was done in conjunction with the repricing of the Company's stock options as discussed in Note 9. The warrants originally were to expire on October 16, 2000. In October 1999, the Company extended the expiration date of all 160,000 outstanding warrants from October 16, 2000 to December 31, 2002. As a result of the extension, the Company recorded approximately $217,000 of stock compensation expense in fourth quarter 1999. In September 2001, one of the Company's directors became an officer of the Company. This individual held 84,666 of the 160,000 warrants discussed above. As part of his employment agreement, he exchanged all 84,666 of his warrants for 18,000 shares of the Company's common stock. NOTE 8. SHAREHOLDER RIGHTS PLAN In June 2001, the Company's Board of Directors declared a dividend on its shares of common stock (the "Common Shares") of preferred share purchase rights (the "Rights") as part of a Shareholder Rights Plan (the "Plan"). The Plan is designed to insure that all shareholders of the Company receive fair value for their Common Shares in the event of a proposed takeover of the Company and to guard against the use of partial tender offers or other coercive tactics to gain control of the Company without offering fair value to the Company's shareholders. At the present time, the Company knows of no proposed or threatened takeover, tender offer or other effort to gain control of the Company. Under the terms of the Plan, the Rights will be distributed as a dividend at the rate of one Right for each Common Share held. Shareholders will not actually receive certificates for the Rights, but the Rights will become part of each Common Share. All Rights expire on June 30, 2006. Each Right will entitle the holder to buy shares of common stock at an exercise price of $40.00. The Rights will be exercisable and will trade separately from the Common Shares only if a person or group acquires beneficial ownership of 20% or more of the Company's Common Shares or commences a tender or exchange offer that would result in such a person or group owning 20% or more of the Common Shares. Only when one or more of these events occur will shareholders receive certificates for the Rights. If any person actually acquires 20% or more of the Common Shares -- other than through a tender or exchange offer for all Common Shares that provides a fair price and other terms for such shares -- or if a 20% or more shareholder engages in certain "self-dealing" transactions or engages in a merger or other business combination in which the Company survives and its Common Shares remain outstanding, the other shareholders will be able to exercise the Rights and buy Common Shares of the Company having twice the value of the exercise price of the Rights. In other words, payment of the $40.00 per Right exercise price will entitle the holder to acquire $80.00 worth of Common Shares. Additionally, if the Company is involved in certain other mergers where its shares are exchanged, or certain major sales of assets occur, shareholders will be able to purchase the other party's common shares in an amount equal to twice the value of the exercise price of the Rights. The Company will be entitled to redeem the Rights at $.01 per Right at any time until the tenth day following public announcement that a person has acquired a 20% ownership position in Common Shares of the Company. The Company in its discretion may extend the period during which it can redeem the Rights. NOTE 9. STOCK COMPENSATION At December 31, 2001, the Company had two stock-based compensation plans. As permitted under SFAS No. 123, the Company has elected to continue to measure compensation costs using the intrinsic value method of accounting prescribed by APB Opinion No. 25. Under that method, the difference between the exercise price and the market value of the shares at the date of grant is charged to compensation expense, ratably over the vesting period, with a corresponding increase in shareholders' equity. Compensation costs charged against income for all plans were $1,840,000, $545,000 and $21,000 for 2001, 2000 and 1999, respectively. Under the Mallon Resources Corporation 1988 Equity Participation Plan (the "1988 Equity Plan"), 250,000 shares of common stock have been reserved in order to provide for incentive compensation and awards to employees and consultants. The 1988 Equity Plan provides that a three-member committee may grant stock options, awards, stock appreciation rights, and other forms of stock-based compensation in accordance with the provisions of the 1988 Equity Plan. The options vest over a period of up to four years and expire over a maximum of 10 years from the date of grant. In June 1997, the shareholders approved the Mallon Resources Corporation 1997 Equity Participation Plan (the "1997 Plan") under which shares of common stock have been reserved to provide employees, consultants and directors of the Company with incentive compensation. The 1997 Plan is administered by a committee of the Board of Directors who may, in its sole discretion, select the participants, and determine the number of shares of common stock to be subject to incentive stock options, non-qualified options, stock appreciation rights and other stock awards in accordance with the provisions of the 1997 Plan. The aggregate number of shares of common stock that may be issued under the 1997 Plan is equal to 11% of the number of outstanding shares of common stock from time to time. This authorization may be increased from time to time by approval of the Board of Directors and by the ratification of the shareholders of the Company. In 2001, the Committee approved the grant of 475,000 stock options with an exercise price of $0.01 each. In 2000, the Committee approved the grant of 122,384 stock options with an exercise price of $0.01 each and 4,000 stock options at above fair value. No options were granted under the 1997 Plan during 1999. The options vest over a period of up to five years and expire over a maximum of 10 years from the date of grant. In 1997, the Company granted to a consultant options to purchase 3,000 of the Company's common shares at $8.50 per share, exercisable from November 1997 to December 2000 which expired unexercised. In 1999, the Company granted this same individual additional options to purchase 3,000 of the Company's common shares at $8.50 per share, exercisable from January 1999 to December 2001. The exercise price of these 3,000 options were reduced from $8.50 per share to $0.01 per share in 2001 and were exercised in 2001. These options were not part of either the 1988 Equity Plan or the 1997 Plan. During 2001 and 1999, the Company recorded $2,000 and $22,000 of compensation expense related to these options. No compensation expense related to these options was recorded in 2000. The following table summarizes activity with respect to all outstanding stock options.
Weighted Average Shares Exercise Price Outstanding at December 31, 1998 817,404 $6.25 Granted 3,000 8.50 Exercised (392,235) 6.82 Forfeited (10,200) 6.88 Outstanding at December 31, 1999 417,969 5.71 Granted 126,384 0.23 Exercised (18,567) 0.03 Forfeited (16,133) 5.76 Outstanding at December 31, 2000 509,653 4.55 Granted 475,000 0.01 Exercised (94,734) 0.01 Forfeited (125,864) 5.52 Outstanding at December 31, 2001 764,055 2.10 ======== ===== Options exercisable: December 31, 1999 200,017 $4.95 ======== ===== December 31, 2000 324,564 $4.68 ======== ===== December 31, 2001 359,597 $4.45 ======== =====
The weighted average remaining contractual life of the options outstanding under both the 1988 Equity Plan and 1997 Plan at December 31, 2001 is approximately 8 years. In January 2001, the Company granted a total of 25,000 shares of restricted common stock and charged $76,000 against income, based on the fair market value of the shares as of the date of grant. In April 1997, the Company granted a total of 25,000 shares of restricted common stock to three of its officers as an inducement to continue in its employ. The fair market value of the shares at the date of grant was charged ratably over the vesting period of three years. The Company charged $-0-, $7,000 and $37,000 against income in 2001, 2000 and 1999, respectively, related to this grant. The grant of restricted stock was not a part of the Company's equity plans. Had compensation expense for the Company's 2001, 2000 and 1999 grants of stock-based compensation been determined consistent with the fair value based method under SFAS No. 123, the Company's net loss, net loss attributable to common shareholders, and the net loss per share attributable to common shareholders would approximate the pro forma amounts below:
2001 2000 1999 As Pro As Pro As Pro Reported Forma Reported Forma Reported Forma (In thousands) Net loss $(31,365) $(31,705) $(6,531) $(6,664) $(2,777) $(3,266) Net loss attributable to common shareholders (31,991) (32,331) (7,044) (7,177) (3,013) (3,502) Net loss per share attributable to common shareholders (2.99) (3.03) (0.83) (0.84) (0.41) (0.48)
The fair value of each option is estimated as of the grant date, using the Black-Scholes option-pricing model, with the following assumptions:
Risk-free interest rate 4.55% 6.6% 6.3% Expected life (in years) 6 6 5 Expected volatility 99.25% 93.8% 69.5% Expected dividends 0.0% 0.0% 0.0% Weighted average fair value of options granted $6.38 $5.84 $5.28
In July 1999, the Company adopted a Stock Ownership Encouragement Program to encourage holders of options to exercise their rights to purchase shares of the Company's common stock. Under the program, the Company may lend option holders the funds necessary to exercise their options. Funds advanced are immediately paid to the Company in connection with the exercise of the options. As a result, the Company incurs no cash outlay. Loans made under the program must be approved by the Board of Directors or by its Compensation Committee, and are represented by secured, interest-bearing, full recourse promissory notes from the participants. In September 1999, certain officers of the Company exercised options to purchase 381,360 shares of common stock at an exercise price of $6.88 per share, and borrowed funds from the Company to do so. The notes bore interest at 7%, which was due along with the principal in August 2002. In October 2000, the Company amended the notes to extend the due date of the principal and accrued interest from August 2002 to August 2004 and to provide for the cancellation of the notes upon the occurrence of a "Change of Control" of the Company as defined in the Company's bylaws. The notes and accrued interest were reflected as a reduction of shareholders' equity in the accompanying consolidated balance sheets for 2000. In May 2001, in connection with a termination settlement reached with a former officer of the Company, the Company purchased certain interests in an oil and gas limited liability company from the officer valued at $350,000. The proceeds were used to reduce the balance of the note receivable from the officer. The remaining principal and accrued interest on the note of $364,000 was forgiven and is reflected as a non-cash charge to general and administrative expense for the year ended December 31, 2001 in the accompanying consolidated statements of operations. In addition, because 76,066 unvested options to purchase shares of the Company's common stock vested upon his termination and became immediately exercisable, the Company recorded a non-cash charge of $195,000 to general and administrative expense for the year ended December 31, 2001 in the accompanying consolidated statements of operations. This charge is included in the total expensed in 2001 for all stock compensation plans discussed above. In June 2001, the Company's Board of Directors approved a measure to forgive a portion of the interest and principal on the notes receivable from the remaining officers. For accounting purposes, the Company has treated the partial forgiveness as a repurchase of the common stock underlying the notes receivable, a cancellation of the notes receivable and the grant of options to purchase 287,462 shares of common stock at $1.00 per share. In connection with the assumed repurchase of common stock and the cancellation of the notes receivable, the Company recorded a non-cash charge of $533,000, which is reflected in general and administrative expense for the year ended December 31, 2001 in the accompanying consolidated statements of operations. The options to purchase 287,462 shares of common stock discussed above are treated as variable awards for accounting purposes. Compensation expense will be recognized for the amount of any increases in the stock price above the exercise price of $1.00 until the options are exercised, forfeited or expire unexercised. Any decreases in the stock price will be recognized as a decrease in compensation expense, limited to the amount of compensation expense previously recognized as a result of increases in the stock price. As a result of the variable nature of the options discussed above, the Company recorded a non-cash charge of $581,000 for the year ended December 31, 2001, which is reflected in general and administrative expense and is based on the change in the stock price from the exercise price of $1.00. In June 2001, the Compensation Committee of Mallon's Board of Directors adopted a policy that, upon a change of control of the Company, the exercise price on outstanding stock options held by then current employees of the Company will be reduced to $0.01 from an average exercise price of $6.88. At December 31, 2001, 193,864 outstanding stock options were affected by this new policy. Under the provisions of FASB Interpretation No. 44, "Accounting for Certain Transactions Involving Stock Compensation," the Company will be required to account for the options as variable awards from the modification date until the date the options are exercised, forfeited or expire unexercised. Compensation expense will be recognized for the amount of any increases in the stock price above the original exercise price per share until the options are exercised, forfeited or expire unexercised, or until a change of control event occurs. Any decreases in the stock price will be recognized as a decrease in compensation expense, limited to the amount of compensation expense previously recognized as a result of increases in the stock price. If and when the change of control event occurs, compensation expense will be measured for the difference between the stock price on that date and $0.01 per share and will be recognized as a non-cash charge to general and administrative expense. As of December 31, 2001, no compensation expense had been recorded related to the options discussed above. NOTE 10. BENEFIT PLANS Effective January 1, 1989, the Company and its affiliates established the Mallon Resources Corporation 401(k) Profit Sharing Plan (the "401(k) Plan"). The Company and its affiliates match contributions to the 401(k) Plan in an amount up to 25% of each employee's monthly contributions. The Company may also contribute additional amounts at the discretion of the Compensation Committee of the Board of Directors, contingent upon realization of earnings by the Company which, at the sole discretion of the Compensation Committee, are adequate to justify a corporate contribution. For the years ended December 31, 2001, 2000 and 1999, the Company made matching contributions of $42,000, $44,000 and $32,000, respectively. No discretionary contributions were made during any of the three years ended December 31, 2001. The Company maintains a program which provides bonus compensation to employees from oil and gas revenues which are included in a pool to be distributed at the discretion of the Chairman of the Board. For the years ended December 31, 2001, 2000 and 1999, a total of $618,000, $156,000 and $141,000, respectively, was distributed to employees. Of the amount distributed in 2001, approximately $398,000 was related to proceeds received from the sale of the Company's Delaware Basin properties. NOTE 11. HEDGING ACTIVITIES The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. Commodity derivatives contracts, which are generally placed with major financial institutions or with counterparties of high credit quality that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices received by the Company. Prior to January 1, 2001, the Company accounted for its commodity derivatives contracts using the hedge (deferral) method of accounting. Under this method, realized gains and losses from the Company's price risk management activities are recognized in oil and gas revenue when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses from commodity derivatives contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a commodity derivatives contract and actual oil and gas prices, a gain or loss would be recognized currently to the extent the commodity derivatives contract did not offset changes in actual oil and gas prices. On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS No. 137 and SFAS No. 138. Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not meet specific hedge accounting criteria or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in other comprehensive income/loss, a component of shareholders' equity, to the extent the hedge is effective. All hedge transactions are subject to the Company's risk management policy, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Under the Aquila Credit Agreement, the Company may be required to maintain price hedging arrangements in place with respect to up to 65% of its oil and gas production. Accordingly, at December 31, 2001, the Company had price swaps covering 3,406,000 MMBtu of gas related to production for 2002-2004 at fixed prices ranging between $2.55-$3.91 per MMBtu. In addition, the Company had outstanding at December 31, 2001 basis swaps to fix the differential between the NYMEX (Henry Hub) price and the index price at which the hedged gas is to be sold for 3,406,000 MMBtu for 2002-2004. The following table indicates the Company's outstanding energy swaps at December 31, 2001:
Product Production Fixed Price Duration Reference Gas (MMBtu) 1,558,000 $2.55-$3.91 1/02-12/02 NYMEX (Henry Hub) Gas (MMBtu) 996,000 $2.55 1/03-12/03 NYMEX (Henry Hub) Gas (MMBtu) 852,000 $2.55 1/04-12/04 NYMEX (Henry Hub)
The Company had price swaps covering 171,000 barrels of oil related to production from its Delaware Basin properties for 2001-2004 at fixed prices ranging from $17.38-$17.81 per barrel. In September 2001, in conjunction with the sale of the Delaware Basin properties (see Note 2), the Company settled the crude oil swaps for a total cost of $1,325,000. At December 31, 2001, this transaction is reflected as a part of the loss on the sale of oil and gas properties. At December 31, 2001, the Company had recorded a current derivative asset of $229,000, a long-term derivative liability of $1.4 million and an unrealized loss of $1.2 million in accumulated other comprehensive loss. No related income tax effects were recorded because of the Company's net operating loss carryforward. On January 1, 2001, in accordance with the transition provisions of SFAS No. 133, the Company recorded a loss of $15.2 million in accumulated other comprehensive loss representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. The Company recorded corresponding cash flow hedge derivative liabilities of $15.2 million. During 2001, losses of $3.3 million were transferred from accumulated other comprehensive loss to oil and gas revenues related to settled positions and an unrealized gain of $10.7 million was recorded to other comprehensive income to adjust the fair value of the open positions. The Company expects to reclassify as increases to earnings during the next twelve months approximately $229,000 of unrealized hedging gains in accumulated other comprehensive loss at December 31, 2001. For the years ended December 31, 2001, 2000 and 1999, the Company's losses under its swap agreements were $3,292,000, $8,965,000 and $102,000, respectively, and are included in oil and gas sales in the Company's consolidated statements of operations. At December 31, 2001, the estimated net amount the Company would have paid to terminate its outstanding energy swaps and basis swaps, described above, was approximately $1,194,000. NOTE 12. MAJOR CUSTOMERS Sales to customers in excess of 10% of total revenues for the years ended December 31, 2001, 2000 and 1999 were:
2001 2000 1999 (In thousands) Customer A $11,422 $11,970 $2,368 Customer B 5,288 5,161 2,347 Customer C 1,894 3,274 2,025 Customer D -- -- 4,087
NOTE 13. INCOME TAXES The Company incurred a loss for book and tax purposes in all periods presented. There is no income tax benefit or expense for the years ended December 31, 2001, 2000 and 1999. Deferred tax assets are comprised of the following as of December 31, 2001 and 2000:
2001 2000 (In thousands) Deferred Tax Assets: Net operating loss and percentage depletion carryforward $ 18,496 $ 14,491 Oil, gas and other property basis differences 8,121 -- Other 1,211 387 Total deferred tax assets 27,828 14,878 Deferred Tax Liabilities: Oil, gas and other property basis differences -- (2,101) Net deferred tax assets 27,828 12,777 Less valuation allowance (27,828) (12,777) Net deferred tax assets $ -- $ -- ======== ========
In 2001, in connection with the sale of the Delaware Basin oil and gas properties (see Note 2), the Company utilized approximately $7,300,000 of a previously unrecognized capital loss carryforward to offset capital gain realized on the sale. At December 31, 2001, for Federal income tax purposes, the Company had a net operating loss carryforward of approximately $47,300,000, which expires in varying amounts between 2002 and 2021. In addition, at December 31, 2001, the Company had a percentage depletion carryforward of approximately $2,300,000, which will not expire. NOTE 14. RELATED PARTY TRANSACTIONS In January and February 2002, the Company forgave certain notes receivable from certain officers and a director of the Company plus accrued interest totaling $57,556. Accordingly, a provision for $57,556 was made in December 2001 to reduce the carrying value of the notes. Please refer to Note 9 for discussion regarding the partial forgiveness of certain notes receivable from related-party shareholders in May and June 2001. In July 1999, the Company entered into a financial consulting services contract with Bear Ridge Capital LLC, which is wholly-owned by one of the Company's directors. In September 2001, this individual became an officer of the Company. Under the contract, Bear Ridge Capital was paid a monthly retainer and was issued warrants to purchase an aggregate of 40,000 shares of the Company's common stock at a per share exercise price of $0.01. Warrants covering 10,000 shares of the Company's common stock vested on July 1, 2001. The remaining warrants were forfeited (see Note 7). During 2001, 2000 and 1999, the Company paid Bear Ridge Capital $99,000, $121,000 and $110,000 in fees, respectively, and expensed $3,000, $26,000 and $25,000 in stock compensation expense, respectively, related to the warrants. In September 2001, this consulting agreement was terminated and the Company entered into an employment agreement with the principal of Bear Ridge Capital LLC. In February 2000, the Compensation Committee of the Company's Board of Directors granted to the Chairman of the Company certain overriding royalty interests burdening certain oil and gas concessions that the Company may be awarded by the Government of Costa Rica. NOTE 15. SUPPLEMENTARY INFORMATION ON OIL AND GAS OPERATIONS Certain historical costs and operating information relating to the Company's oil and gas producing activities as of and for the years ended December 31, 2001, 2000 and 1999 are as follows:
2001 2000 1999 (In thousands) Capitalized Costs Relating to Oil and Gas Activities: Oil and gas properties (see notes 1-4 below) $ 93,933 $120,972 $103,315 Natural gas processing plant 8,648 8,560 8,341 Accumulated depreciation, depletion and amortization (1), (3), (4) (69,669) (58,408) (52,884) $ 32,912 $ 71,124 $ 58,772 ======== ======== ======== Costs Incurred in Oil and Gas Producing Activities: Property acquisition costs $ 816 $ 578 $ 123 Exploration costs 2,872 2,860 2,080 Development costs: Gas plant processing 88 219 80 Pipeline 3,026 1,593 1,646 Salt water disposal -- 63 326 Drilling 10,701 12,867 5,502 $ 17,503 $ 18,180 $ 9,757 ======== ======== ======== Results of Operations from Oil and Gas Producing Activities: Oil and gas sales $ 19,340 $ 16,803 $ 13,138 Lease operating expense (12,049) (7,595) (5,107) Depletion and depreciation (6,776) (5,828) (4,587) Impairment of oil and gas properties (1) (16,418) -- -- Results of operations from oil and gas producing activities $(15,903) $ 3,380 $ 3,444 ======== ======== ========
__________ (1) In the third quarter of 2001, the net book value of the Company's oil and gas properties exceeded the net present value of the underlying reserves. Accordingly, the Company wrote-down its oil and gas properties at September 30, 2001 by $16,418,000, utilizing commodity prices subsequent to September 30, 2001. At December 31, 2001, 2000 and 1999, the net present value of the underlying reserves exceeded the net book value of the Company's oil and gas properties. (2) Includes $2,104,000 of unevaluated property costs not being amortized at December 31, 2001, of which $884,000 is related to Costa Rica. In 2001, 2000 and 1999, $792,000, $341,000 and $107,000 were incurred, respectively, of which $427,000, $304,000 and $43,000, respectively, were related to Costa Rica. The Company anticipates that substantially all unevaluated costs will be classified as evaluated costs within 5 years. (3) During 2000, the Company retired $304,000 of oil and gas properties and accumulated depletion related to Offshore Belize. (4) During 2001, the Company sold its oil and gas properties in the Delaware Basin. As discussed in Note 2, because the sale significantly altered the relationship between the Company's capitalized costs and its proved oil and gas reserves, the Company recognized a loss on the sale of oil and gas properties of $3,128,000 million for the year ended December 31, 2001. The loss included costs of approximately $32,521,000 from an allocation of the Company's total undepleted full cost pool at June 30, 2001, between the properties sold and the properties retained, based on the relative estimated fair value of the properties sold and retained. (5) Lease operating expense in 2001 includes assessments for possessory interest taxes, interest and penalties of approximately $2,200,000 for 1998- 2000 and $1,100,000 for 2001, which the Company is protesting. Estimated Quantities of Proved Oil and Gas Reserves (unaudited): Set forth below is a summary of the changes in the net quantities of the Company's proved crude oil and natural gas reserves estimated by independent consulting petroleum engineering firms for the years ended December 31, 2001, 2000 and 1999. All of the Company's reserves are located in the continental United States.
Oil Gas (MBbls) (MMcf) Proved Reserves Reserves, December 31, 1998 1,264 84,161 Extensions, discoveries and additions 482 47,020 Production (172) (5,600) Revisions 322 (33,056) Reserves, December 31, 1999 1,896 92,525 Acquisitions of reserves in place 1 144 Extensions, discoveries and additions -- 35,813 Production (171) (6,022) Revisions 412 (11,989) Reserves, December 31, 2000 2,138 110,471 Sales of reserves in place (1,782) (28,858) Extensions, discoveries and additions (2) 12,690 Production (105) (5,954) Revisions (221) (35,210) Reserves, December 31, 2001 28 53,139 ====== ======= Proved Developed Reserves December 31, 1998 945 65,786 ====== ======= December 31, 1999 1,204 38,539 ====== ======= December 31, 2000 1,494 47,334 ====== ======= December 31, 2001 16 37,635 ====== =======
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (unaudited): The following summary sets forth the Company's unaudited future net cash flows relating to proved oil and gas reserves, based on the standardized measure prescribed in SFAS No. 69, for the years ended December 31, 2001, 2000 and 1999:
2001 2000 1999 (In thousands) Future cash in-flows $102,405 $ 960,017 $240,007 Future production costs (43,674) (228,350) (80,667) Future development costs (17,259) (56,057) (31,059) Future income taxes (168) (221,140) (16,514) Future net cash flows 41,304 454,470 111,767 Discount at 10% (15,722) (180,689) (48,719) Standardized measure of discounted future net cash flows, end of year $ 25,582 $ 273,781 $ 63,048 ======== ========= ========
Future net cash flows were computed using yearend prices and yearend statutory income tax rates (adjusted for permanent differences, operating loss carryforwards and tax credits) that relate to existing proved oil and gas reserves in which the Company has an interest. The following are the principal sources of changes in the standardized measure of discounted future net cash flows at December 31, 2001, 2000 and 1999:
2001 2000 1999 (In thousands) Standardized measure, beginning of year $ 273,781 $ 63,048 $ 43,339 Net revisions to previous quantity estimates and other 32,193 (12,422) (10,881) Extensions, discoveries, additions, and changes in timing of production, net of related costs 4,883 120,131 30,107 Sales of reserves in place (111,886) -- -- Purchase of reserves in place -- 122 -- Changes in estimated future development costs 5,860 (21,559) (14,053) Previously estimated development costs incurred during the period 2,293 2,875 2,294 Sales of oil and gas produced, net of production costs (13,906) (18,173) (8,031) Net change in prices and production costs (314,162) 251,949 25,374 Accretion of discount 27,378 7,033 4,215 Net change in income taxes 119,148 (119,223) (9,316) Standardized measure, end of year $ 25,582 $ 273,781 $ 63,048 ========= ========= ========
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting the future rates of production, particularly as to natural gas, and timing of development expenditures. Such estimates may not be realized due to curtailment, shut-in conditions and other factors which cannot be accurately determined. The above information represents estimates only and should not be construed as the current market value of the Company's oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. NOTE 16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited):
First Second Third Fourth Total 2001 (In thousands, except per share amounts) Revenues $ 7,330 $ 5,403 $ 4,161 $ 2,871 $ 19,765 Expenses 7,824 9,714 25,206 8,386 51,130 Net loss $ (494) $(4,311) $(21,045) $(5,515) $(31,365) ======= ======= ======== ======= ======== Net loss attributable to common shareholders $ (656) $(4,462) $(21,199) $(5,674) $(31,991) ======= ======= ======== ======= ======== Net loss per share attributable to common shareholders $ (0.06) $ (0.42) $ (1.98) $ (0.53) $ (2.99) ======= ======= ======== ======= ======= 2000 Revenues $ 3,982 $ 3,251 $ 4,808 $ 5,266 $17,307 Expenses 5,613 5,147 5,912 7,166 23,838 Net loss $(1,631) $(1,896) $ (1,104) $(1,900) $(6,531) ======= ======= ======== ======= ======= Net loss attributable to common shareholders $(1,759) $(2,017) $ (1,226) $(2,042) $(7,044) ======= ======= ======== ======= ======= Net loss per share attributable to common shareholders $ (0.22) $ (0.26) $ (0.16) $ (0.19) $ (0.83) ======= ======= ======== ======= =======
NOTE 17. SUBSEQUENT EVENT: In February 2002, the Company notified Aquila that it would not be in compliance as of December 31, 2001 with one of the covenants under the Aquila Credit Agreement. That covenant requires the Company to maintain projected net revenue attributable to its proved reserves in sufficient amount to fully amortize the balance under the Aquila Credit Agreement by the maturity date of September 9, 2003. As a result, in February 2002, the Aquila Credit Agreement was amended for a second time. This amendment superseded the March 30, 2001, waiver by Aquila regarding the requirement for principal payments. The second amendment contains the following provisions: (i) As long as no new event of default occurs subsequent to the date of the second amendment, Aquila has agreed that through December 31, 2002, it will not exercise any of the remedies available to Aquila due to any event of default that occurs and is continuing regarding the amount of projected net revenue required to amortize the amounts outstanding by September 9, 2003. (ii) Interest on amounts outstanding accrues at prime plus 3% starting January 1, 2002, through September 30, 2002, and increases to prime plus 4% after October 1, 2002. The Company is required to pay interest only on the outstanding balance through December 31, 2002. (iii) The amount available under the agreement was increased by $2.5 million, making the total available $55.9 million. Aquila may, at its discretion, advance additional loans up to $2.5 million to be used for development operations and/or working capital needs of the Company. (iv) A "change of control" provision was added, which calls for the prepayment of the entire outstanding balance, together with any accrued and unpaid interest, at the occurrence of a change of control of the Company. (v) The Company has the option to purchase from Aquila 490,000 shares of the Company's common stock previously issued to Aquila for a price of $2.6 million if a sale of the Company is consummated prior to September 30, 2002. (vi) Aquila's one-time right to require the Company to purchase shares of the Company's common stock previously issued to Aquila (the "Put Option") was amended to provide that Aquila has the option to sell to the Company up to 490,000 shares of the Company's common stock at $10.00 per share if a sale of the Company is consummated at any time after September 30, 2002 and prior to September 9, 2003, or at $12.50 per share if the outstanding balance under the Aquila Credit Agreement is paid on the earlier of September 9, 2003 or the date on which Aquila notifies the Company of the acceleration of payment of the outstanding balance because of the occurrence of an event of default. (vii) The Company issued to Aquila 125,000 shares of the Company's common stock as a part of the amendment. If a sale of the Company is not consummated before October 1, 2002, the Company will issue Aquila an additional 150,000 shares. (viii) Upon a change of control of the Company occurring on or before September 30, 2002, the Company will pay Aquila $500,000. If a change of control of the Company occurs after September 30, 2002, the Company will pay Aquila $1,250,000. Through March 29, 2002, the Company had drawn $800,000 under provision (iii) above, and had $1.7 million available for future draws. 10