-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QMrOdP+TyT5vgJqKquAlTwqAGRgZCfgwBjyqYB4bNJheRPbxmVszlyVFOVqRxPjO h/ntEmNrcRUbniAe3ObQgA== 0000837759-01-000005.txt : 20010409 0000837759-01-000005.hdr.sgml : 20010409 ACCESSION NUMBER: 0000837759-01-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010402 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MALLON RESOURCES CORP CENTRAL INDEX KEY: 0000837759 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 841095959 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-13124 FILM NUMBER: 1592008 BUSINESS ADDRESS: STREET 1: 999 18TH ST STE 1700 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3032932333 MAIL ADDRESS: STREET 1: 999 18TH STREET STREET 2: STE 1700 CITY: DENVER STATE: CO ZIP: 80202 10-K 1 0001.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, 2000 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 16, 2001, 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 $61,289,000. As of March 16, 2001, 10,630,093 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, 2000 Table of Contents PART I Page Items 1 and 2 Business and Properties 1 General History 1 Business Strategies 1 Historical Highlights 2 Our Oil and Gas Properties 2 Gas Sweetening Plant 4 Acreage 4 Summary Oil and Gas Reserve Data 4 Drilling Activity 4 Recompletion Activity 5 Productive Wells 5 Production and Sales 5 Marketing 5 Corporate Offices; Officers, Directors and Key Employees 6 Cautionary Statement Regarding Forward-Looking Statements 7 Risk Factors 8 Item 3 Legal Proceedings 14 Item 4 Submission of Matters to a Vote of Security Holders 14 PART II Item 5 Market for Registrant's Common Equity and Related Stockholder Matters 15 Price Range of Common Stock 15 Holders 15 Dividend Policy 15 Item 6 Selected Financial Data 16 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 17 Overview 17 Liquidity and Capital Resources 17 Results of Operations 18 Hedging Activities 21 Miscellaneous 21 Item 7A Quantitative and Qualitative Disclosure about Market Risk 22 Commodity Price Risk 22 Interest Rate Risk 22 Item 8 Financial Statements and Supplementary Data 23 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 23 PART III Item 10 Directors and Executive Officers of the Registrant 24 Item 11 Executive Compensation 24 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-6 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 substantially all of our estimated proved reserves are located in the San Juan and Delaware Basins. We have accumulated significant acreage positions in these two basins, in which we have been active since 1982. We believe our technical and operational experience and our database of information enable us to effectively exploit and develop our properties. We have increased our estimated proved reserves from 34.5 Bcfe as of December 31, 1996, to 123.3 Bcfe as of December 31, 2000, a 257% increase. As of December 31, 2000, our proved reserves consisted of 110.5 billion cubic feet of natural gas and 2.1 million barrels of crude oil, with a pre-tax PV-10 of $393.0 million. At December 31, 2000, we owned interests in 337 gross (184 net) producing wells and operated 216, or 64%, 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, Dallas, 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 and Delaware Basins. 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. The recent increases in our estimated proved reserves and rates of production are attributable primarily to oil and gas fields discovered or extended by our exploration through exploitation activities. - - Controlling Our Operations. For the year ended December 31, 2000, approximately 92% 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 and Delaware Basins, 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 reduce costs. - - Making Strategic Acquisitions. We also make acquisitions of properties located within our core areas of operations. We believe that our knowledge of the San Juan and Delaware Basins allows us to effectively identify and evaluate acquisition opportunities. Historical Highlights In September 1993, we purchased our core 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 accelerate the pace of our development of our inventory of oil and gas properties. In May 1998, we significantly increased our acreage in East Blanco Field by entering into a Minerals Development Agreement with the Jicarilla Apache Tribe. This acreage is adjacent to our original East Blanco acreage, and brings our total acreage in the field to approximately 60,700 gross acres. In early 1999, we began testing the southern portion of our East Blanco acreage in an effort to extend the field limits. We have now drilled a total of 44 wells in this effort, which has successfully confirmed that East Blanco Field extends to the south. 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. Our Oil and Gas Properties We are active in the San Juan Basin of northwestern New Mexico and in the Delaware Basin of southeastern New Mexico. At December 31, 2000, these areas accounted for substantially all of our estimated proved reserves, with approximately 81.3 Bcfe attributable to our San Juan Basin properties and approximately 41.8 Bcfe attributable to our Delaware Basin properties. San Juan Basin, Northwestern New Mexico 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, 2000, we owned interests in approximately 67,800 gross (64,900 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. During 2001, we plan to commence a pilot program to test the Fruitland Coal Formation and Lewis Shale, which are present throughout much of our East Blanco acreage. We are actively involved in efforts to acquire additional acreage in the East Blanco area and other portions of the San Juan Basin. East Blanco Field, Rio Arriba County, New Mexico We own interests in approximately 60,700 gross 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 116 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 73%. As of December 31, 2000, our estimated proved reserves in East Blanco Field were approximately 79.2 Bcfe, or approximately 64.2% of our total estimated proved reserves. During 2000, we drilled 28 wells and recompleted seven wells 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, 2000, Gavilan Field contained approximately 1.9 Bcfe or approximately 1.5% 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 80%. 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, 2000, Otero Field contained only a nominal portion of our total estimated proved reserves. Delaware Basin, Southeastern New Mexico The Delaware Basin of southeast New Mexico, where we own interests in approximately 35,000 gross (13,700 net) acres, containing 191 gross (66 net) wells, has been an area of significant activity for us since 1982. Our Delaware Basin properties are located primarily in fields with established production histories, which typically contain multiple productive geologic formations and zones. Our wells in the Delaware Basin produce from a variety of formations, the principal of which are the Cherry Canyon, Brushy Canyon, Bone Spring, Strawn and Morrow Formations. The Cherry Canyon, Brushy Canyon and Bone Spring Formations primarily produce oil at shallow to medium drilling depths, while the deeper Strawn and Morrow generally produce natural gas. Our primary properties in the Delaware Basin are in the White City, Black River, South Carlsbad, Lea Northeast, and Quail Ridge Fields. We also continue to assess potential in our Shipp, Lovington Northeast and Brushy Draw properties. Based upon our operations to date, we have identified 76 potential drilling targets on our Delaware Basin acreage. White City, Black River, and Carlsbad Fields, Eddy County, New Mexico. We have leasehold interests in approximately 8,480 gross (4,560 net) acres in these adjacent fields. As of December 31, 2000, our estimated proved reserves in these three fields were approximately 18.9 Bcfe, or 15.3% of our total estimated proved reserves. Because greater drilling densities were recently approved in this area, much of our developed acreage in these fields now contain additional drilling opportunities for Morrow Formation natural gas. Lea Northeast Field and Quail Ridge, Lea County, New Mexico. We own and operate approximately 6,010 gross (3,070 net) acres in these adjacent fields. Our working interest averages approximately 71% in Lea Northeast and 48% in Quail Ridge. As of December 31, 2000, our estimated proved reserves in these fields were approximately 14.4 Bcfe or 11.7% of our total estimated proved reserves. In these fields, we own interests in 34 gross (20.13 net) wells, of which we operate 28. Wells produce from the Cherry Canyon, Bone Spring and Morrow Formations. Because greater drilling densities were recently approved in this area, much of our developed acreage in this field now offers additional drilling opportunities for Morrow Formation natural gas. Our acreage also has additional Bone Spring Formation drilling opportunities. Shipp and Lovington Northeast Fields, Lea County, New Mexico. Shipp and Lovington Fields are comprised of a collection of individual reservoirs, or algal mounds, in a Strawn Formation interval at depths of approximately 11,500 feet. The mounds range in size from approximately 100 to approximately 700 acres. We have interests in 30 wells and operate 20 wells in these adjacent fields. Our working interest averages approximately 41% in Lovington Northeast and 63% in Shipp. As of December 31, 2000, these fields contained only a nominal portion of our total estimated proved reserves. Brushy Draw Field, Eddy County, New Mexico. Our initial drilling and field development began here in 1982. Current production is from the base of the Cherry Canyon Formation, at a depth of approximately 5,000 feet. We operate 14 wells with an average working interest of approximately 66%. As of December 31, 2000, Brushy Draw 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, Wyoming, 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 substantially all 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, 2000:
Developed Undeveloped Area Gross Net Gross Net San Juan Basin 23,244 20,611 44,584 44,246 Delaware Basin 29,045 9,799 6,000 3,943 Other 10,980 1,096 1,928 324 Total 63,269 31,506 52,512 48,513
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, 2000, based on a report prepared by Reed W. Ferrill & Associates, Inc., independent petroleum engineers. Ferrill & Associates 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 $8.23 per Mcf for natural gas and $23.83 per barrel for oil.
December 31, 2000 Proved Reserves: Natural gas (MMcf) 110,471 Oil (MBbl) 2,138 Total (MMcfe) 123,299 Proved Developed Reserves: Natural gas (MMcf) 47,334 Oil (MBbl) 1,494 Total (MMcfe) 56,298 PV-10 (in thousands): $393,004
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 1998 37 7 44 32.64 5.59 38.23 1999 21 1 22 18.05 1.00 19.05 2000 27 1 28 26.72 1.00 27.72
From January 1, 2001 through March 16, 2001, we engaged in the drilling of 12 gross (12 net) wells that are not reflected in the foregoing table. 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 1998 28 2 30 25.10 1.83 26.93 1999 6 1 7 5.67 0.92 6.59 2000 10 0 10 8.42 0 8.42
Productive Wells The following table summarizes our gross and net interests in productive wells at December 31, 2000. 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 4 122 126 3.39 111.87 115.26 Delaware Basin 117 73 190 50.32 14.80 65.12 Other 12 9 21 1.65 1.63 3.28 Total 133 204 337 55.36 128.30 183.66
In addition, we own interests in four waterflood units in the Delaware Basin, which contain a total of 550 gross wells (8.5 net wells), and 6 gross (3.03 net) produced water disposal wells. 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, 2000 1999 1998 Net Production: Natural gas (MMcf) 6,022 5,600 5,852 Oil (MBbl) 171 172 230 Total (MMcfe) 7,048 6,632 7,232 Average Sales Price Realized (1): Natural gas (per Mcf) $ 2.10 $ 1.81 $ 1.72 Oil (per Bbl) $24.43 $17.38 $12.99 Per Mcfe $ 2.38 $ 1.98 $ 1.81 Average Cost (per Mcfe): Production tax and marketing expense $ 0.49 $ 0.25 $ 0.26 Lease operating expense $ 0.59 $ 0.52 $ 0.47 Depletion $ 0.79 $ 0.65 $ 0.73 ___________________ (1) Includes effects of hedging.
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 21 employees at this office. We maintain field operations offices in Durango, Colorado, and in Carlsbad, New Mexico, where we employ a total of 22 individuals. The following are the members of our Board of Directors and our executive officers:
Name Age Title(s) George O. Mallon, Jr 56 Director, Chairman of the Board, CEO and President Kevin M. Fitzgerald 46 Director, COO and Executive Vice President Roy K. Ross 50 Director, Executive Vice President, Secretary and General Counsel Frank Douglass 67 Director Roger R. Mitchell 68 Director Francis J. Reinhardt, Jr. 71 Director Peter H. Blum 43 Director Alfonso R. Lopez 52 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. Kevin M. Fitzgerald has been Executive Vice President of Mallon since June 1990. He joined Mallon Oil in 1983 as Petroleum Engineer and served as Vice President of Engineering from 1987 through December 1988, when he became President of Mallon Oil and a Vice President of Mallon. Mr. Fitzgerald earned a B.S. degree in Petroleum Engineering from the University of Oklahoma in 1978. 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. 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. Peter H. Blum became a director of Mallon in January 1998. 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. 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 individuals: Ray E. Jones is Vice President - Engineering of Mallon Oil. Before joining Mallon in January 1994, Mr. Jones spent eight years with Jerry R. Bergeson & Associates (now GeoQuest), an independent consulting firm. Mr. Jones graduated from Colorado School of Mines in 1979 and is a registered professional engineer. Wendell A. Bond has been Vice President - Exploration of Mallon Oil since December 1996. Prior to joining Mallon on a full-time basis, Mr. Bond was an independent geological consultant to Mallon since July 1994. Mr. Bond has more than 25 years of experience in the petroleum industry, both domestically and internationally. Prior to joining Mallon, he was president of Wendell A. Bond, Inc., a company specializing in petroleum geological consulting services that he formed in 1988. Prior to 1988, Mr. Bond had been employed in a variety of positions for several independent and major oil and gas companies, including Project Geologist for Webb Resources, District Geologist for Sohio Petroleum and Chief Geologist for Samuel Gary Jr. & Associates. Mr. Bond earned his B.S. degree in geology from Capital University, Columbus, Ohio and his M.S. degree in geology from the University of Colorado. Donald M. Erickson, Jr. has been 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 Denver. Samuel K. Steele has been Vice President - Land of Mallon Oil since December 1999. Mr. Steele has more than 20 years of petroleum land and land management experience. From June 1981 to October 1992 he worked for Union Oil Company of California (UNOCAL), first as a landman then as District Land Manager for the Midcontinent and Rocky Mountain Districts. In 1992, Mr. Steele left UNOCAL to form an independent oil company. Mr. Steele joined Mallon Oil in 1997 as a land consultant. In 1998, Mr. Steele accepted a position with Mallon Oil as a Senior Landman, and in 1999 he was promoted to his current position. Mr. Steele earned a B.A. degree from California State University, Long Beach, in 1973, and a Petroleum Land Management designation from the University of Oklahoma in 1981. 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, 2000, approximately 90% 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 $16.8 million write-down of the carrying value of our oil and gas properties in December 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 in large part 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 two geologic basins 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 our three most senior executive officers. Our operations have not been profitable. We recorded net losses for 1996, 1997, 1998, 1999 and 2000, of $1,837,000, $3,704,000, $18,186,000, $2,777,000, and $6,531,000, 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. In certain circumstances, the holders of our Series B Preferred Stock may have the right to elect members of our Board of Directors. Under the terms of our Series B Preferred Stock, if we do not pay dividends on the Series B Preferred Stock for three quarterly dividend periods, then, until such dividends have been paid in full, the holders of Series B Preferred Stock have the right to elect two additional members to our Board of Directors. While any such directors would not constitute a majority of our Board, it is probable that they would attempt to influence the Board, as a whole, to support the satisfaction of the claims of the holders of the Series B Preferred Stock. 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, but we have since undertaken primary responsibility for resolving matters that arise out of the audit. 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. A determination contrary to our position concerning so-called "major portion" issues was recently rendered by the Department of the Interior. Our interest in this controversy is being represented by the law firm Roberts & Strother, P.C., Farmington, New Mexico, who are counsel of record for the predecessor operator of the properties. Roberts & Strother, P.C. has retained the services of Fulbright & Jaworski L.L.P., Washington, D. C., as associate counsel to assist in an appeal of the Department of the Interior's rulings. Fulbright & Jaworski L.L.P. is in the process of (i) preparing a Petition for Reconsideration to be filed with the Department of the Interior, and (ii) a complaint challenging the Department of the Interior's ruling in Federal District Court. We have recently determined to also attempt to negotiate a private protocol addressing the manner in which royalties are calculated and accounted for, as well. The final outcome of these matters cannot yet be predicted. We have recently exchanged correspondence with the Revenue and Taxation Department of the Jicarilla Apache Tribe concerning the applicability of the Tribe's Possessory Interest Tax to certain of our assets located on Tribal Lands. We, upon the advice of counsel, have taken the position that certain rules and regulations promulgated in December 2000 by the Tribe do not apply to the determination of Possessory Interest Tax for years prior to 2001. The Revenue and Taxation Department disagrees with us as to this point, and by letter dated February 23, 2001, issued Notices of Tax Assessment and Tax Due (in the aggregate amount of $1,651,653) to Mallon Oil for its failure to pay Possessory Interest Tax for 1998, 1999,and 2000. We have (i) requested that the Tribal Council look into the matter and grant us relief, and (ii) engaged the firm of Modrall, Sperling, Roehl, Harris & Sisk, P.A., New Mexico, to represent us in this matter. The final outcome of this matter cannot 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, 1999: First Quarter $8.750 $5.938 Second Quarter 9.438 5.750 Third Quarter 9.125 6.625 Fourth Quarter 8.500 4.000 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 (through March 16) 7.250 5.875
Holders As of March 16, 2001, 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, 2000. 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, 2000 1999 1998 1997 (1) 1996 (1) Selected Statements of Operations Data: (In thousands, except per share data) Revenues: Oil and gas sales $16,803 $13,138 $ 13,069 $ 8,582 $ 5,854 Other 504 160 109 69 512 17,307 13,298 13,178 8,651 6,366 Costs and expenses: Oil and gas production 7,595 5,107 5,273 3,037 2,249 Mining project expenses -- -- -- -- 1,014 Depreciation, depletion and amortization 6,382 4,822 5,544 2,725 2,095 Impairment of oil and gas properties -- -- 16,842 24 264 Impairment of mining properties -- -- -- 350 -- General and administrative 3,609 2,915 2,562 2,274 1,845 Interest and other 6,252 3,126 1,143 701 842 23,838 15,970 31,364 9,111 8,309 Minority interest in loss of consolidated subsidiary -- -- -- -- 266 Equity in loss of affiliate -- -- -- (3,244) -- Loss before extraordinary item (6,531) (2,672) (18,186) (3,704) (1,677) Extraordinary loss on early retirement of debt -- (105) -- -- (160) Net loss (6,531) (2,777) (18,186) (3,704) (1,837) Accretion of mandatorily redeemable common stock (428) (116) -- -- -- Dividends on preferred stock and accretion (85) (120) (120) (185) (376) Preferred stock conversion inducement -- -- -- (403) -- Gain on redemption of preferred stock -- -- -- -- 3,743 Net income (loss) attributable to common shareholders $(7,044) $ (3,013) $(18,306) $(4,292) $ 1,530 Per Share Data: Loss attributable to common shareholders before extraordinary item $ (0.83) $ (0.40) $ (2.61) $ (0.92) $ (0.82) Extraordinary loss -- (0.01) -- -- (0.06) Net loss attributable to common shareholders $ (0.83) $ (0.41) $ (2.61) $ (0.92) $ (0.88) Weighted average shares outstanding 8,525 7,283 7,015 4,682 2,512 Other Data: Capital expenditures $18,207 $ 9,852 $ 36,354 $20,169 $ 6,339 Selected Balance Sheet Data: Working capital (deficit) $ 377 $ (2,678) $ (3,782) $ 1,190 $ 5,365 Total assets 91,710 65,426 58,452 51,426 41,400 Long-term debt (2) 40,180 34,874 27,183 1 3,511 Mandatorily redeemable preferred stock 798 1,341 1,329 1,317 3,900 Mandatorily redeemable common stock (3) 4,248 3,450 -- -- -- Shareholders' equity 28,536 19,490 22,164 40,196 21,904
(1) The financial information for 1996 is consolidated information that includes the accounts of Laguna Gold Company ("Laguna"). In 1997, we deconsolidated Laguna and reflected our interest in Laguna using the equity method. See Note 3 to our consolidated financial statements. (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 7 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, 2000 and 1999, and results of operations and cash flows for each of the years ended December 31, 2000, 1999 and 1998. 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 and Delaware Basins, and prevailing prices for oil and 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 oil and gas prices can be expected to continue to be subject to wide fluctuations in the future. A substantial or extended decline in oil or 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 oil and gas reserves that we may produce economically. Liquidity and Capital Resources 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. Our current 2001 capital expenditure budget is approximately $30 million, with which we plan to drill or recomplete approximately 50 wells. To fund these expenditures, we plan to use approximately $14 million of the net proceeds from our October 2000 equity offering (described below), with the remainder to be funded with expected cash flow from operations. Currently, the amount available under our Aquila agreement is approximately $1.1 million. Beginning in March, substantially all of our cash flow from operations was to be used to make principal payments to Aquila. On March 30, 2001, Aquila agreed to waive the requirement for principal payments. Instead, the repayment schedule for the twelve months beginning April 30, 2001 is as follows: (i) for the months April 2001 to September 2001, we will pay interest only, or approximately $2.5 million, and (ii) from October 2001 to March 2002, we will make monthly principal and interest payments of $700,000 or a total of $4.2 million. Aquila will evaluate the loan monthly and, at its sole discretion, can discontinue the repayment schedule described above and revert to the requirement of principal payments equal to defined cash flow. We anticipate the Aquila Credit Agreement will be amended during second quarter 2001 to reflect the changes described above. We will continue to seek to increase the amount available under the Aquila Credit Agreement and to revise the repayment requirements. However, there can be no assurance that we will be successful in our efforts to further amend the Aquila Credit Agreement. 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 will be used primarily to finance our oil and gas drilling activities. In September 1999, we established our credit agreement with Aquila. The initial amount available under the agreement was $45.7 million, which was increased to $53.4 million in November 2000. By its current terms, the amount available under the agreement may be increased to as much as $60 million, as new reserves are added through our development drilling program. At March 16, 2001, we had drawn approximately $52.2 million under the Aquila agreement, leaving approximately $1.1 million available. However, under the current terms of the Aquila agreement, the remaining amount available may not be drawn for capital expenditures. The Aquila facility is secured by substantially all of our oil and gas properties. Interest on the Aquila facility accrues at prime plus 2% and was added to the loan balance through March 31, 2001. The outstanding loan balance is due in full on September 9, 2003. As part of the Aquila financing, we also entered into a four year agency agreement with Aquila under which we pay a marketing fee equal to 1% of the net proceeds (as defined) from the sale of all of our oil and gas production to market our gas and to negotiate our gas purchase contracts. In addition, we also issued to Aquila 490,000 shares of common stock. Aquila also has a one-time right to require us to purchase 490,000 of our common shares from Aquila at $12.50 per share during the 30-day period beginning September 9, 2003. 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 $384,000 and $110,000 to Universal Compression during 2000 and 1999, respectively. During 1999, prior to its retirement, we made principal payments of $783,000 on the Bank One term loan. 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 (at 8.5%) is payable quarterly beginning October 1, 1998. We repaid $15,000 and $11,000 of this loan during 2000 and 1999, respectively. In March 1999, the due date of the loan was extended from July 1999 to April 2002. 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 will be required to redeem the remaining 80,000 shares of Series B Preferred Stock in April 2001 at $10.00 per share, and plan to do so with available funds. The Series B Preferred Stock is convertible to common stock automatically if the common stock trades at a price in excess of 140% of the then applicable conversion price for each day in a period of 10 consecutive trading days. The conversion price is currently $9.18. 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, 2000 1999 1998 (In thousands, except per unit data) Operating Results from Oil and Gas Operations: Oil and gas revenues $16,803 $13,138 $13,069 Production tax and marketing expense 3,422 1,682 1,901 Lease operating expense 4,173 3,425 3,372 Depletion 5,570 4,319 5,303 Depreciation 258 268 140 Impairment -- -- 16,842 Net Production: Natural gas (MMcf) 6,022 5,600 5,852 Oil (MBbl) 171 172 230 Total (MMcfe) 7,048 6,632 7,232 Average Sales Price Realized (1): Natural gas (per Mcf) $ 2.10 $ 1.81 $ 1.72 Oil (per Bbl) $24.43 $17.38 $12.99 Per Mcfe $ 2.38 $ 1.98 $ 1.81 Average Cost Data (per Mcfe): Production tax and marketing expense $ 0.49 $ 0.25 $ 0.26 Lease operating expense $ 0.59 $ 0.52 $ 0.47 Depletion $ 0.79 $ 0.65 $ 0.73 ________________
(1) Includes effects of hedging. See "Hedging Activities." 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. Oil and Gas Production Expenses. Oil and gas production expenses for the year ended December 31, 2000 increased 49% to $7,595,000 from $5,107,000 for the year ended December 31, 1999. The increase was primarily attributable to increases in production taxes due 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 ("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 will be 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. Year Ended December 31, 1999 Compared to Year Ended December 31, 1998 Revenues. Total revenues for the year ended December 31, 1999 increased 1% to $13,298,000 from $13,178,000 for the year ended December 31, 1998. Oil and gas sales for the year ended December 31, 1999 increased 1% to $13,138,000 from $13,069,000. The increase was due to higher oil and gas prices. Oil production for the year ended December 31, 1999 decreased 25% to 172,000 barrels from 230,000 barrels for the year ended December 31, 1998 and gas production for the year ended December 31, 1999 decreased 4% to 5,600,000 Mcf from 5,852,000 Mcf for the year ended December 31, 1998. Production for 1999 was down from 1998 because our 1999 drilling and recompletion program was delayed pending the receipt of additional financing, which we received in September 1999. During fourth quarter 1999, we drilled or recompleted 19 wells with funds from the refinancing. Production decreases were offset by increases in average oil and gas prices realized in 1999 from those realized in 1998. Average oil prices for the year ended December 31, 1999 increased 34% to $17.38 per barrel from $12.99 per barrel for the year ended December 31, 1998 and average gas prices for the year ended December 31, 1999 increased 5% to $1.81 per Mcf from $1.72 per Mcf for the year ended December 31, 1998. Oil and Gas Production Expenses. Oil and gas production expenses for the year ended December 31, 1999 decreased 3% to $5,107,000 from $5,273,000 for the year ended December 31, 1998. The decrease was primarily attributable to one- time production tax credits. Production tax and marketing expense per Mcfe decreased $.01, or 4%, to $0.25 for the year ended December 31, 1999 from $0.26 for the year ended December 31, 1998. Lease operating expense ("LOE") per Mcfe increased $0.05, or 11%, to $0.52 for the year ended December 31, 1999 from $0.47 for the year ended December 31, 1998. LOE per Mcfe in 1999 is higher primarily due to workovers. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended December 31, 1999 decreased 13% to $4,822,000 from $5,544,000 for the year ended December 31, 1998, primarily due to lower depletion expense. Depletion per Mcfe for the year ended December 31, 1999 decreased 11% to $0.65 from $0.73 for the year ended December 31, 1998, primarily due to a lesser cost base resulting from the write-down of oil and gas properties of $16.8 million in fourth quarter 1998, discussed below. Impairment of Oil and 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. 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, even if prices declined for only a short period of time. We made a non-cash charge in fourth quarter 1998 to write down our U.S. oil and gas properties by $16,842,000. In applying the "ceiling test," we used December 31, 1998 oil and gas prices of $10.03 per barrel of oil and $1.43 per Mcf of gas. We currently operate only in the continental United States. General and Administrative Expenses. General and administrative expenses for the year ended December 31, 1999 increased 14% to $2,915,000 from $2,562,000 for the year ended December 31, 1998. The increase is primarily due to stock compensation expense of $217,000 recognized in fourth quarter 1999 related to the extension of the expiration date of certain warrants to purchase our common stock. In addition, in fourth quarter of 1999 we expensed $177,000 of costs related to an equity offering which we did not consummate. Interest and Other Expenses. Interest and other expenses for the year ended December 31, 1999 increased 173% to $3,126,000 from $1,143,000 for the year ended December 31, 1998. The increase is primarily due to higher outstanding borrowings. Income Taxes. We incurred net operating losses for U.S. Federal income tax purposes in 1999 and 1998, 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, 1999 and 1998. At December 31, 1999, we had a net operating loss carryforward for U.S. Federal income tax purposes of $28,000,000, which will begin to expire in 2000. 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, 1999 decreased 85% to $2,777,000 from $18,186,000 for the year ended December 31, 1998 as a result of the factors discussed above. The net loss for the year ended December 31, 1998, includes $16,842,000 relating to a non-cash write-down of oil and gas properties discussed above. We paid the 8% dividend of $108,000 on $1,341,000 and $1,329,000 face amount Series B Mandatorily Redeemable Convertible Preferred Stock in each of the years ended December 31, 1999 and 1998, respectively, and realized accretion of $12,000 in each year. In 1999, we issued 420,000 shares of mandatorily redeemable common stock, in conjunction with a refinancing. 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 will be accreted over a period of 49 months. During 1999, we realized accretion of $116,000 related to these shares. Net loss attributable to common shareholders for the year ended December 31, 1999 was $3,013,000 compared to net loss attributable to common shareholders of $18,306,000 for the year ended December 31, 1998. 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) gains of ($8,965,000), ($102,000) and $481,000 for the years ended December 31, 2000, 1999 and 1998, 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 following table summarizes our derivative financial instrument position on our natural gas and crude oil production as of December 31, 2000. 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, 2000. 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 and crude oil production. See "Hedging Activities" above.
Natural Gas: Fixed Price Year MMBtu per MMBtu Fair Value 2001 2,392,000 $2.55-$4.68 $(8,484,000) 2002 1,558,000 $2.55-$3.91 (2,717,000) 2003 996,000 $2.55 (1,311,000) 2004 852,000 $2.55 (1,066,000) Crude Oil: Fixed Price Year Bbls per Bbl Fair Value 2001 60,000 $17.38 - $18.61 $ (440,000) 2002 60,000 $17.40 (337,000) 2003 48,000 $17.40 (206,000) 2004 48,000 $17.40 (167,000)
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 216,000 barrels of oil related to production for 2001-2004 at fixed prices ranging from $17.38-$18.61 per barrel and to hedge a total of 5,798,000 MMBtu of gas related to production for 2001-2004 at fixed prices ranging from $2.55- $4.68 per MMBtu. In addition, we entered into basis swaps to fix the differential between the NYMEX price and the index price at which the hedged gas is to be sold for 5,798,000 MMBtu for 2001 - 2004. At December 31, 2000, these swaps had a fair value of $502,000. In November 2000, we entered into one-year "costless collar" contracts pursuant to which we hedged the price of 60,000 MMBtu per month beginning January 2001 based on an El Paso-Permian Index. We will receive $3.85 per MMBtu if the settlement price is below $3.85 per MMBtu. If the settlement price is greater than $5.80 per MMBtu, we will pay the difference between such settlement price and $5.80 per MMBtu. At December 31, 2000, the fair value of the put and call contracts was a loss of $(945,000). 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) There- Fair 2001 2002 2003 2004 2005 after value Long-term debt: Fixed rate $454 $609 $ 569 $3,498 $ -- $ -- $ 5,130 Average interest rate 12.7% 12.1% 12.8% 12.8% -- -- Variable rate $11,725 $7,484 $30,833 $ -- $ -- $ -- $50,042 Average interest rate 11.5% 11.5% 11.5% -- -- --
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, 2000 to our chief executive officer and our four other most highly compensated individuals whose total compensation, exceeded $100,000 for such year.
SUMMARY COMPENSATION TABLE Annual Compensation Long Term Compensation Awards Other Annual Restricted Securities All Other Name and Principal Compensation Stock Awards Underlying Compensation Position Year Salary($) Bonus($) ($) ($) Options(#) (S) G.O. Mallon, Jr. 2000 175,000 46,320 -- -- 24,000 2,625 CEO 1999 175,000 29,530 -- -- -- 2,500 1998 174,000 48,107 -- -- 98,094 2,500 K.M. Fitzgerald 2000 145,000 21,145 -- -- 17,000 2,625 E.V.P. 1999 145,000 16,405 -- -- -- 2,500 1998 144,000 31,062 -- -- 55,533 2,500 R.K. Ross 2000 140,000 21,625 -- -- 9,384 2,625 E.V.P. 1999 140,000 13,390 -- -- -- 2,500 1998 140,000 18,672 -- -- 39,915 2,500 A.R. Lopez 2000 97,050 14,924 -- -- 8,000 2,625 Treasurer 1999 92,400 9,465 -- -- -- 2,500 D.M. Erickson 2000 115,500 10,485 -- -- 8,000 2,625 VP Operations 1999 110,000 8,295 -- -- -- 2,500 of Mallon Oil 1998 100,000 11,802 -- -- -- 2,500
OPTION GRANTS IN 2000 Individual Grants Number of Securities Percent of Total Exercise or Grant Date Underlying Options Option Granted Base Price Expiration Present Value Name Granted (#) In Fiscal Year ($/Sh) Date (1) ($) G.O. Mallon, Jr. 24,000 19.0% $0.01 12/31/09 $142,320 K.M. Fitzgerald 17,000 13.5% $0.01 12/31/09 $100,810 R.K. Ross 9,384 7.4% $0.01 12/31/09 $ 55,647 A.R. Lopez 8,000 6.3% $0.01 12/31/09 $ 47,440 D.M. Erickson 8,000 6.3% $0.01 12/31/09 $ 47,440
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 - 6.6%; expected life in years - 6; expected volatility - 94%; 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, 2000, as well as the value of unexercisable "in the money" options at that date.
AGGREGATE OPTION EXERCISES IN 2000 AND YEAR-END OPTION VALUES Number of Securities Underlying Value of Unexercised Value Unexercised Options In-The-Money Options Shares Acquired Realized At December 31, 2000 (1) At December 31, 2000 ($)(1) Name On Exercise (#) ($) Exercisable Unexercisable Exercisable Unexercisable G.O. Mallon, Jr. -- -- 40,825 -- 295,355 -- K.M. Fitzgerald 7,750 $39,897 46,466 68,948 147,698 122,309 R.K. Ross -- -- 26,397 45,625 62,642 73,471 A.R. Lopez -- -- 21,867 8,133 26,509 39,661 D.M. Erickson -- -- 18,667 9,333 135,149 67,571
(1) Amounts shown represent aggregated fair market value at the share price on December 31, 2000 of $7.25 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, Douglass and Blum. The terms of any awards made under the Plans are within the broad discretion of the Committee. At December 31, 2000, the following options to purchase shares of our common stock were issued and outstanding under the Plans: 506,653 $4.53
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 30, 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. 545,724 (2) 5.11% Kevin M. Fitzgerald 213,828 (3) 2.00% Roy K. Ross 109,574 (4) 1.03% Frank Douglass 62,677 (5) * Roger R. Mitchell 67,480 (6) * Francis J. Reinhardt, Jr. 69,253 (7) * Peter H. Blum 127,068 (8) 1.18% Centennial Energy Partners, L.L.C. 756,200 (9) 7.11% Wellington Management Company, LLP 1,031,000 (9) 9.70% All officers and directors as a group (8 persons) 1,224,438 (10) 11.09% __________ * Less than 1%
1. The address of Messrs. Mallon, Fitzgerald and Ross 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, Moorseville, NC 28117. The address of Mr. Reinhardt is 650 Madison Ave., 23rd Floor, New York, NY 10022. The address of Mr. Blum is 4 Trapping Way, Pleasantville, NY 10570. The address of Centennial Energy Partners L.L.C. is 900 Third Avenue, Suite 1801, New York, NY 10022. The address of Wellington Management Company, LLP is 75 State Street, Boston, MA 02109. 2. Includes 2,166 shares owned by Mr. Mallon's wife and 47,491 shares that could be acquired by Mr. Mallon upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 132,000 shares covered by stock options that have not yet vested. 3. Includes 81,014 shares that could be acquired by Mr. Fitzgerald upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 76,066 shares covered by stock options that have not yet vested. 4. Includes 52,160 shares that could be acquired by Mr. Ross upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 56,528 shares covered by stock options that have not yet vested. 5. Includes 33,073 shares that could be acquired by Mr. Douglass upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 3,333 shares covered by stock options that have not yet vested. 6. Includes 28,403 shares that could be acquired by Mr. Mitchell upon the exercise of immediately exercisable stock options that he holds. Does not include 3,333 shares covered by stock options that have not yet vested. 7. Includes 31,068 shares that could be acquired by Mr. Reinhardt upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 3,333 shares covered by stock options that have not yet vested. 8. Includes 111,568 shares that could be acquired by Mr. Blum upon the exercise of immediately exercisable stock options and warrants that he holds. Does not include 53,833 shares covered by stock options and warrants that have not yet vested. 9. Based upon information contained in various public filings made with the S.E.C. 10. Includes 412,111 shares that could be acquired upon the exercise of immediately exercisable stock options and warrants. Does not include 351,092 shares covered by stock options and warrants that have not yet vested. ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS We serve as operator of certain oil and gas properties in which some of our officers and directors have working interests. Such individuals pay their pro- rata share of all costs relating to the properties, on the same basis as other unaffiliated interest owners. Mr. Fitzgerald, one of our directors and executive officers, owns royalty interests that burden certain of our properties. Under our "Stock Ownership Encouragement Program," in August 1999, Messrs. Mallon, Fitzgerald and Ross borrowed $1,585,018, $645,549, and $391,284, respectively, from us that they used to exercise certain options owned by them. Messrs. Mallon, Fitzgerald 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. Payment of the notes is secured, in part, by a pledge of the stock acquired upon the exercise of the options. 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 July 1999, we entered into a financial consulting services contract (which has since been amended) with Bear Ridge Capital LLC, which is wholly- owned by Mr. Blum, one of our directors. Under the contract, Bear Ridge Capital is 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. During 2000 and 1999, we paid Bear Ridge Capital $121,000 and $110,000 in fees, respectively. We entered into a letter agreement dated February 2, 2000, by which we are committed to grant to George O. Mallon, Jr. certain overriding royalty interests burdening certain oil and gas concessions we may be awarded by the Government of Costa Rica. 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. (2) Financial Statements Schedules The financial statements for the year ended December 31, 2000 of Laguna are not filed as financial statement schedules to this report as Laguna is in the process of liquidating its assets. (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 2000: Date of Report Item(s) Reported November 21, 2000 "Other Events" - Operating Plans and Outlook (c) Exhibits: See the Exhibit Index that follows the signature page to this report and is incorporated herein by this reference. (d) Financial statements of 50-percent-or-less-owned persons: The financial statements for the year ended December 31, 2000 of Laguna are not filed as financial statement schedules to this report as Laguna is in the process of liquidating its assets. 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 2, 2001 By: /s/ George O. Mallon, Jr. George O. Mallon, Jr. Principal Executive Officer Date: April 2, 2001 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 2, 2001 By: /s/ George O. Mallon, Jr. George O. Mallon, Jr. Director Date: April 2, 2001 By: /s/ Kevin M. Fitzgerald Kevin M. Fitzgerald Director Date: April 2, 2001 By: /s/ Roy K. Ross Roy K. Ross Director Date: April 2, 2001 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 # *10.02 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 # 10.06 (Amended and Restated) Employment Contract with COO # 10.07 (Amended and Restated) Employment Contract of Executive Vice President # 10.08 Consulting Agreement with Bear Ridge Capital LLC # *10.09 Severance and Sale Program (7) *10.10 Stock Ownership Encouragement Program (8) *10.11 Promissory Note and Stock Pledge of CEO (7) *10.12 Promissory Note and Stock Pledge of COO (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) 10.16 Amendment to Promissory Note of CEO # 10.17 Amendment to Promissory Note of COO # 10.18 Amendment to Promissory Note of Executive Vice President # 10.19 Letter Agreement dated February 2000 with George O. Mallon, Jr. # 10.20 Memorandum dated October 19, 1998 re Kevin M. Fitzgerald # *21.01 Subsidiaries (4) ____________________________
* 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. # 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-6 Notes to Consolidated Financial Statements F-7 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, 2000 and 1999, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Denver, Colorado March 16, 2001 (except with respect to the matter discussed in Note 18, as to which the date is March 30, 2001) MALLON RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands, except share data)
ASSETS December 31, 2000 1999 Current assets: Cash and cash equivalents $ 14,155 $ 1,230 Accounts receivable: Oil and gas sales 3,460 1,315 Joint interest participants, net of allowance of $39 and $43, respectively 353 559 Related parties 1 53 Other 18 153 Inventories 215 200 Other 123 83 Total current assets 18,325 3,593 Property and equipment: Oil and gas properties, full cost method 120,972 103,315 Natural gas processing plant 8,560 8,341 Other property and equipment 1,112 1,084 130,644 112,740 Less accumulated depreciation, depletion and amortization (59,057) (53,428) 71,587 59,312 Notes receivable-related parties 7 84 Debt issuance costs, net 1,529 1,885 Other, net 262 552 Total Assets $ 91,710 $ 65,426 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Trade accounts payable $ 3,689 $ 4,883 Undistributed revenue 2,045 934 Accrued taxes and expenses 35 55 Current portion of long-term debt 12,179 399 Total current liabilities 17,948 6,271 Long-term debt, net of unamortized discount of $2,813 and $3,146, respectively 40,180 34,874 Total liabilities 58,128 41,145 Commitments and contingencies (Note 5) Series B Mandatorily Redeemable Convertible Preferred Stock, $0.01 par value, 500,000 shares authorized, 80,000 and 135,200 shares issued and outstanding, respectively, liquidation preference and mandatory redemption of $800 and $1,352, respectively 798 1,341 Mandatorily Redeemable Common Stock, $0.01 par value, 490,000 and 420,000 shares authorized, issued and outstanding, respectively, mandatory redemption of $6,125 and $5,250, respectively 4,248 3,450 Shareholders' equity: Common Stock, $0.01 par value, 25,000,000 shares authorized, 10,115,093 and 7,413,300 shares issued and outstanding, respectively 101 74 Additional paid-in capital 92,456 76,723 Accumulated deficit (61,155) (54,624) Notes receivable from shareholders (2,866) (2,683) Total shareholders' equity 28,536 19,490 Total Liabilities and Shareholders' Equity $ 91,710 $ 65,426
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, 2000 1999 1998 Revenues: Oil and gas sales $ 16,803 $ 13,138 $ 13,069 Interest and other 504 160 109 17,307 13,298 13,178 Costs and expenses: Oil and gas production 7,595 5,107 5,273 Depreciation, depletion and amortization 6,382 4,822 5,544 Impairment of oil and gas properties -- -- 16,842 General and administrative, net 3,609 2,915 2,562 Interest and other 6,252 3,126 1,143 23,838 15,970 31,364 Loss before extraordinary item (6,531) (2,672) (18,186) Extraordinary loss on early retirement of debt -- (105) -- Net loss (6,531) (2,777) (18,186) Accretion of mandatorily redeemable common stock (428) (116) -- Dividends and accretion on preferred stock (85) (120) (120) Net loss attributable to common shareholders $ (7,044) $ (3,013) $(18,306) Basic loss per share: Loss attributable to common shareholders before extraordinary item $ (0.83) $ (0.40) $ (2.61) Extraordinary loss -- (0.01) -- Net loss attributable to common shareholders $ (0.83) $ (0.41) $ (2.61) Basic weighted average common shares outstanding 8,525 7,283 7,015
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)
Notes Additional Receivable Common Stock Paid-In Accumulated from Shares Amount Capital Deficit Shareholders Total Balance, December 31, 1997 6,995,264 $ 70 $73,787 $(33,661) $ -- $ 40,196 Employee stock options granted -- -- 195 -- -- 195 Employee stock options exercised 13,657 -- 12 -- -- 12 Stock issued to directors 729 -- -- -- -- -- Conversion of warrants 11,415 -- -- -- -- -- Issuance of restricted common stock to officers -- -- 67 -- -- 67 Dividends on preferred stock -- -- (108) -- -- (108) Accretion of preferred stock -- -- (12) -- -- (12) Net loss -- -- -- (18,186) -- (18,186) Balance, December 31, 1998 7,021,065 70 73,941 (51,847) -- 22,164 Employee stock options granted -- -- 66 -- -- 66 Employee 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 -- -- 17 -- -- 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 Employee stock options granted -- -- 761 -- -- 761 Employee 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
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, 2000 1999 1998 Cash flows from operating activities: Net loss $ (6,531) $ (2,777) $(18,186) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 6,382 4,822 5,544 Impairment of oil and gas properties -- -- 16,842 Accrued interest expense added to long-term debt 4,738 998 -- Accrued interest income added to notes receivable from shareholders (183) (60) -- Extraordinary loss -- 105 -- Stock compensation expense 578 323 196 Amortization of discount on long-term debt and installment obligation 705 188 22 Provision for losses on accounts receivable -- -- 35 Changes in operating assets and liabilities: (Increase) decrease in: Accounts receivable (1,535) (540) 2,097 Inventory and other current assets (48) (22) (169) (Decrease) increase in: Trade accounts payable and undistributed revenue (83) 408 (2,240) Accrued taxes and expenses (17) (97) 147 Deferred revenue -- (909) 909 Drilling advances -- (1) (132) Net cash provided by operating activities 4,006 2,438 5,065 Cash flows from investing activities: Additions to property and equipment (17,818) (9,826) (35,977) Proceeds from sale of property and equipment -- -- 40 Decrease (increase) in notes receivable-related parties 77 5 (71) Net cash used in investing activities (17,741) (9,821) (36,008) Cash flows from financing activities: Proceeds from long-term debt 12,414 43,332 28,714 Payments of long-term debt (399) (34,404) (222) Payment of installment obligation -- -- (400) Payment of lease obligations -- -- (2,061) Debt issuance costs (81) (1,995) -- Net proceeds from sale of common stock in public offering 15,287 -- -- Payment of preferred dividends (77) (108) (108) Payment of current note payable for redemption of preferred stock (552) -- -- Proceeds from stock option and warrant exercises 68 55 12 Net cash provided by financing activities 26,660 6,880 25,935 Net increase (decrease) in cash and cash equivalents 12,925 (503) (5,008) Cash and cash equivalents, beginning of year 1,230 1,733 6,741 Cash and cash equivalents, end of year $ 14,155 $ 1,230 $ 1,733 Supplemental cash flow information: Cash paid for interest $ 773 $ 1,988 $ 1,066 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 -- Acquisition of equipment under lease obligations -- -- 315
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. Principles of Consolidation: The consolidated financial statements include the accounts of Mallon Oil and all of its wholly-owned subsidiaries. The Company accounts for its investment in Laguna Gold Company ("Laguna") using the equity method of accounting. 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 on-balance sheet 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, 2000 and 1999, 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 off-balance sheet financial instruments consist of derivative instruments which are intended to manage commodity price risks (see Note 12). 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. 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, 2000 and 1999, 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, 2000 and 1999 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 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 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 10). In March 2000, the 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 12). The information presented in Note 12 of the consolidated financial statements represents all of the Company's derivative financial instruments outstanding as of December 31, 2000, 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 (in accordance with paragraph 28a of SFAS 133) 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 other comprehensive loss for the fair market value of derivative contracts designated as hedges, and a corresponding $15.2 million derivative liability. Comprehensive Income: There are no components of comprehensive income which have been excluded from net income and, therefore, no separate statement of comprehensive income has been presented. 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 statement of operations for 2000, 1999 and 1998 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 2000. NOTE 2. OIL AND GAS PROPERTIES 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, even if prices declined for only a short period of time. The Company recorded a charge in the fourth quarter of 1998 to write down its oil and gas properties by $16,842,000. In applying the "ceiling test," the Company used December 31, 1998 oil and gas prices of $10.03 per barrel of oil and $1.43 per Mcf of gas. 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. LAGUNA GOLD COMPANY Mallon owns an approximate 35% equity interest in Laguna which it accounts for using the equity method. In 1997, the Company's share of Laguna's cumulative net loss exceeded Mallon's carrying value of its investment in and advances to Laguna. As a result, the Company has not reflected its share of Laguna's subsequent losses. Laguna is in the process of liquidating its assets. NOTE 4. NOTES PAYABLE AND LONG-TERM DEBT Long-term debt consists of the following:
2000 1999 (In thousands) Note payable to Aquila Energy Capital Corporation, due 2003 $ 50,042 $32,890 Less unamortized discount (2,813) (3,146) 47,229 29,744 Lease obligation to Universal Compression, Inc. 5,006 5,390 8.5% unsecured note payable to Bank One, Colorado, N.A., due 2002 124 139 52,359 35,273 Less current portion (12,179) (399) Total $ 40,180 $34,874
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"). The initial amount available under the agreement was $45.7 million. The amount available may be increased to as much as $60 million as new reserves are added through the Company's planned development drilling program. The borrowing base is subject to redetermination annually on or before April 30. Aquila delayed its April 2000 redetermination until certain wells drilled by the Company during the first four months of 2000 were completed and their reserves evaluated. The Company had delayed its completion of the wells pending receipt of approval form the Jicarilla Apache Tribe to commingle gas from different zones. The approval was received in April 2000. 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. At December 31, 2000, the Company had drawn $50.0 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. On March 30, 2001, the Company negotiated a change in the terms of its agreement with Aquila to delay the required repayment of principal (see Note 18). 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, 2000 was 11.5%. 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 $119,000 and $31,000 were recorded as oil and gas production expense in 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, 2000 and 1999 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 $439,000 and $109,000 is included in the Company's 2000 and 1999 consolidated statements of operations, respectively. In conjunction with the establishment and subsequent amendment of the Aquila Credit Agreement, the Company issued to Aquila 490,000 shares of the Company's common stock (see Note 7). 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 $384,000 and $110,000 to Universal Compression during 2000 and 1999, respectively. The obligation bears interest at an imputed interest rate of 12.8%. During 1999, prior to its retirement, the Company made principal payments of $783,000 on the Equipment Loan. 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 (at 8.5%) is payable quarterly beginning October 1, 1998. The Company repaid $15,000 and $11,000 of this loan during 2000 and 1999, respectively. In March 1999, the due date of the loan was extended from July 1999 to April 2002. Estimated principal payments on outstanding debt at December 31, 2000 are as follows:
(In thousands) 2001 $12,179 2002 8,093 2003 31,402 2004 3,498 Thereafter -- $55,172
Because the principal payments to Aquila are based on Defined Cash Flow, the estimated principal payments above are based on the Company's best estimates of future cash flow and the timing of principal payments made to Aquila may vary significantly from the estimated principal payments above. NOTE 5. 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, 2000 are as follows:
(In thousands) 2001 $331 2002 89 2003 7 Thereafter -- $427
Rent expense was $373,000, $305,000 and $233,000 for the years ended December 31, 2000, 1999 and 1998, respectively. Contingencies: In February 2001, the Revenue and Taxation Department of the Jicarilla Apache Tribe (the "Tribe") issued to the Company Possessory Interest Tax assessments for 1998, 1999 and 2000 totaling $1,651,700. The Company has taken the position that certain rules and regulations promulgated in December 2000 by the Tribe do not apply to the determination of Possessory Interest Tax for years prior to 2001. The Company has: 1) requested that the Tribal Council grant the Company relief, and 2) engaged New Mexico counsel to represent it. The final outcome of this matter cannot yet be predicted. In April 1999, Mallon Oil filed a civil action to collect approximately $265,000 of unpaid joint-interest billings from Wadi Petroleum, Inc. relating to certain oil and gas properties operated by the Company. In April 2000, the Company settled the matter for a payment to the Company of $150,000 and the assignment to the Company of certain oil and gas properties. 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. The Company has reached an agreement with the Plaintiff whereby Mallon Oil will pay the Plaintiff $50,000 in cash. Final documents effectuating the agreement are in the process of being prepared. 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 6. 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 bears an 8% dividend payable quarterly, and is convertible into shares of the Company's common stock at a current adjusted conversion price of $9.18 per share. 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 $77,000, $108,000 and $108,000 were paid in 2000, 1999 and 1998, respectively. Accretion of preferred stock issue costs was $8,000, $12,000 and $12,000 in 2000, 1999 and 1998, 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 will be required to redeem the remaining 80,000 shares of Series B Stock in April 2001 at $10.00 per share. The Series B Stock is convertible to common stock automatically if the common stock trades at a price in excess of 140% of the then applicable conversion price for each day in a period of 10 consecutive trading days. NOTE 7. 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 will be accreted to the redemption date using the effective interest method. Accretion of $428,000 and $116,000 was recorded during the years ended December 31, 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 2000 and 1999. NOTE 8. 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, 2000 and 1999, 80,000 and 135,200 shares of Series B Preferred Stock were outstanding, respectively. Common Stock: The Company has reserved approximately 87,146 shares, as adjusted, of common stock for issuance upon possible conversion of the remaining Series B 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 will be used primarily to finance the Company's oil and gas drilling activities. Warrants: The Company has outstanding warrants to purchase an aggregate of 200,000 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 is 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 vest on July 1, 2001. During 2000 and 1999, the Company recorded $26,000 and $25,000, respectively, of stock compensation expense related to these warrants. The remaining warrants do not vest except in the event of certain corporate transactions. The warrants expire December 31, 2004. Bear Ridge Capital is wholly-owned by one of the Company's directors. 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'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 10. 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. NOTE 9. SHAREHOLDER RIGHTS PLAN In April 1997, 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 April 22, 2001. 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 10. STOCK COMPENSATION At December 31, 2000, 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 $545,000, $21,000 and $128,000 for 2000, 1999 and 1998, 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 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. In 1998, the Committee approved the grant of 271,842 stock options at fair market value. The options vest over a period of up to five years and expire over a maximum of 10 years from the date of grant. On December 11, 1998, the Company's Board of Directors reduced the exercise price of substantially all outstanding options to purchase shares of the Company's common stock to $6.88 per share, the closing price of the stock on that day. A total of 230,629 options with an original exercise price of $7.50 and 478,850 options with an original exercise price of $8.38 were repriced. 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. These options were not part of either the 1988 Equity Plan or the 1997 Plan. During 1999, the Company recorded $22,000 of compensation expense related to these options. The Stock Compensation Plan for Outside Directors ("the Stock Compensation Plan") provided that the Company's outside directors be compensated by periodic grants of the Company's $0.01 par value common stock worth $1,000 for each board meeting, but no less than $4,000 per year, for each outside director. The Company did not recognize any expense for the years 2000, 1999 and 1998 in relation to the Stock Compensation Plan. In 1998, 10,942 stock options under this plan were issued to the outside directors at fair market value. All available awards under this plan have been granted. The following table summarizes activity with respect to all outstanding stock options.
Weighted Average Shares Exercise Price Outstanding at December 31, 1997 548,277 $6.06 Granted 282,784 6.36 Exercised (13,657) 0.89 Forfeited -- -- 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 Options exercisable: December 31, 1998 497,304 $6.16 December 31, 1999 200,017 $4.95 December 31, 2000 324,564 $4.68
The weighted average remaining contractual life of the options outstanding under both the 1988 Equity Plan and 1997 Plan at December 31, 2000 is approximately 7 years. 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 will be charged ratably over the vesting period of three years. The Company charged $7,000, $37,000 and $67,000 against income in 2000, 1999 and 1998, respectively, related to this grant. The grant of restricted stock is not a part of the Company's equity plans. Had compensation expense for the Company's 2000, 1999 and 1998 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:
2000 1999 1998 As Pro As Pro As Pro Reported Forma Reported Forma Reported Forma Net loss $(6,531) $(6,664) $(2,777) $(3,266) $(18,186) $(19,107) Net loss attributable to common shareholders (7,044) (7,177) (3,013) (3,502) (18,306) (19,227) Net loss per share attributable to common shareholders (0.83) (0.84) (0.41) (0.48) (2.61) (2.74)
The fair value of each option is estimated as of the grant date, using the Black-Scholes option-pricing model, with the following assumptions:
2000 1999 1998 Risk-free interest rate 6.6% 6.3% 4.75% Expected life (in years) 6 5 4 Expected volatility 93.8% 69.5% 64.6% Expected dividends 0.0% 0.0% 0.0% Weighted average fair value of options granted $5.84 $5.28 $3.59
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 bear 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 have been reflected as a reduction of shareholders' equity in the accompanying consolidated balance sheets. NOTE 11. 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, 2000, 1999 and 1998, the Company made matching contributions of $44,000, $32,000 and $28,000, respectively. No discretionary contributions were made during any of the three years ended December 31, 2000. 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, 2000, 1999 and 1998, a total of $156,000, $141,000 and $130,000, respectively, was distributed to employees. NOTE 12. 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. The Company accounts 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. 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, 2000, the Company had entered into agreements to hedge a total of 216,000 barrels of oil related to production for 2001-2004 at fixed prices ranging from $17.38-$18.61 per barrel and to hedge a total of 5,798,000 MMBtus of gas related to production for 2001- 2004 at a fixed price ranging between $2.55-$4.68 per MMBtu. The following table indicates the Company's outstanding energy swaps at December 31, 2000:
Annual Market Price Product Production Fixed Price Duration Reference Gas (MMBtu) 2,392,000 $2.55-$4.68 1/01-12/01 NYMEX (Henry Hub) 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) Oil (Bbls) 60,000 $17.38-$18.61 1/01-12/01 NYMEX Oil (Bbls) 60,000 $17.40 1/02-12/02 NYMEX Oil (Bbls) 48,000 $17.40 1/03-12/03 NYMEX Oil (Bbls) 48,000 $17.40 1/04-12/04 NYMEX
In addition, the Company entered into a basis swap to fix the differential between the NYMEX price and the index price at which the hedged gas is to be sold for 5,798,000 MMBtu for 2001-2004. In November 2000, the Company entered into one-year "costless collar" contracts pursuant to which the Company hedged the price of 60,000 MMBtu per month beginning January 2001 based on an El Paso- Permian Index. The Company will receive $3.85 per MMBtu if the settlement price is below $3.85 per MMBtu. If the settlement price is greater than $5.80 per MMBtu, the Company will pay the difference between such settlement price and $5.80 per MMBtu. For the years ended December 31, 2000, 1999 and 1998, the Company's (losses) gains under its swap agreements were $(8,965,000), $(102,000) and $481,000, respectively, and are included in oil and gas sales in the Company's consolidated statements of operations. At December 31, 2000, the estimated net amount the Company would have paid to terminate its outstanding energy swaps and basis swaps, described above, was approximately $15,171,000. NOTE 13. MAJOR CUSTOMERS Sales to customers in excess of 10% of total revenues for the years ended December 31, 2000, 1999 and 1998 were:
2000 1999 1998 (In thousands) Customer A $11,970 $2,368 $6,610 Customer B 5,161 2,347 -- Customer C 3,274 2,025 2,155 Customer D -- 4,087 --
NOTE 14. 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, 2000, 1999 or 1998. Deferred tax assets are comprised of the following as of December 31, 2000 and 1999:
2000 1999 (In thousands) Deferred Tax Assets: Net operating loss carryforward $ 14,491 $ 10,395 Oil, gas and other property basis differences -- 1,718 Other 387 249 Total deferred tax assets 14,878 12,362 Deferred Tax Liabilities: Oil, gas and other property basis differences (2,101) -- Net deferred tax assets 12,777 12,362 Less valuation allowance (12,777) (12,362) Net deferred tax assets $ -- $ --
At December 31, 2000, for Federal income tax purposes, the Company had a net operating loss carryforward of approximately $38,800,000, which expires in varying amounts between 2001 and 2020. NOTE 15. RELATED PARTY TRANSACTIONS The accounts receivable from related parties consists primarily of joint interest billings to directors, officers, shareholders, employees and affiliated entities for drilling and operating costs incurred on oil and gas properties in which these related parties participate with Mallon Oil as working interest owners. These amounts will generally be settled in the ordinary course of business, without interest. 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. Under the contract, Bear Ridge Capital is 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 (see Note 8). During 2000 and 1999, the Company paid Bear Ridge Capital $121,000 and $110,000 in fees, respectively, and expensed $26,000 and $25,000 in stock compensation expense, respectively, related to the warrants. 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 16. 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, 2000, 1999 and 1998 are as follows:
2000 1999 1998 (In thousands) Capitalized Costs Relating to Oil and Gas Activities: Oil and gas properties (1) (2) $120,972 $103,315 $ 93,624 Natural gas processing plant 8,560 8,341 8,275 Accumulated depreciation, depletion and amortization (58,408) (52,884) (48,297) $ 71,124 $ 58,772 $ 53,602 Costs Incurred in Oil and Gas Producing Activities: Property acquisition costs $ 578 $ 123 $ 1,459 Exploration costs 2,860 2,080 2,091 Development costs: Gas plant processing 219 80 5,497 Pipeline 1,593 1,646 3,970 Salt water disposal 63 326 1,527 Drilling 12,867 5,502 21,447 $ 18,180 $ 9,757 $ 35,991
__________ (1) At December 31, 1998, the net book value of the Company's oil and gas properties exceeded the net present value of the underlying reserves by $16,842,000. Accordingly, the Company wrote-down its oil and gas properties at December 31, 1998. At December 31, 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 $1,243,000 of unevaluated property cost not being amortized at December 31, 2000, of which $257,000, $110,000 and $533,000 were incurred in 2000, 1999 and 1998, respectively. 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. 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, 2000, 1999 and 1998. All of the Company's reserves are located in the continental United States.
Oil Gas (MBbls) (MMcf) Proved Reserves Reserves, December 31, 1996 1,707 24,285 Acquisitions of reserves in place -- 3,968 Extensions, discoveries and additions 340 29,858 Production (196) (2,350) Revisions (470) (5,889) Reserves, December 31, 1997 1,381 49,872 Acquisitions of reserves in place 17 1,119 Extensions, discoveries and additions 7 43,510 Production (230) (5,852) Revisions 89 (4,488) 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 Proved Developed Reserves December 31, 1998 945 65,786 December 31, 1999 1,204 38,539 December 31, 2000 1,494 47,334
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, 2000, 1999 and 1998:
2000 1999 1998 (In thousands) Future cash in-flows $ 960,017 $240,007 $133,311 Future production costs (228,350) (80,667) (47,850) Future development costs (56,057) (31,059) (13,627) Future income taxes (221,140) (16,514) -- Future net cash flows 454,470 111,767 71,834 Discount at 10% (180,689) (48,719) (28,495) Standardized measure of discounted future net cash flows, end of year $ 273,781 $ 63,048 $ 43,339
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 for the years ended December 31, 2000, 1999 and 1998:
2000 1999 1998 (In thousands) Standardized measure, beginning of year $ 63,048 $ 43,339 $ 41,165 Net revisions to previous quantity estimates and other (12,422) (10,881) (3,159) Extensions, discoveries, additions, and changes in timing of production, net of related costs 120,131 30,107 21,189 Purchase of reserves in place 122 -- 617 Changes in estimated future development costs (21,559) (14,053) (4,202) Previously estimated development costs incurred during the period 2,875 2,294 4,663 Sales of oil and gas produced, net of production costs (18,173) (8,031) (5,545) Net change in prices and production costs 251,949 25,374 (22,643) Accretion of discount 7,033 4,215 4,529 Net change in income taxes (119,223) (9,316) 6,725 Standardized measure, end of year $ 273,781 $ 63,048 $ 43,339
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 17. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited):
First Second Third Fourth Total 2000 (In thousands, except per share amounts) 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) 1999 Revenues $ 3,038 $ 2,940 $ 3,560 $ 3,760 $13,298 Expenses 3,909 3,412 3,607 5,042 15,970 Net loss before extraordinary item $ (871) $ (472) $ (47) $(1,282) $(2,672) Net loss attributable to common shareholders $ (901) $ (502) $ (182) $(1,428) $(3,013) Net loss per share attributable to common shareholders: Before extraordinary item $ (0.13) $ (0.07) $ (0.02) $ (0.18) $ (0.40) Extraordinary item -- -- (0.01) -- (0.01) Net loss per share attributable to common shareholders $ (0.13) $ (0.07) $ (0.03) $ (0.18) $ (0.41)
NOTE 18. SUBSEQUENT EVENT: On March 30, 2001, Aquila agreed to waive the requirement for principal payments equal to the Defined Cash Flow. Instead, the repayment schedule for the twelve months beginning April 30, 2001 is as follows: (i) for the months April 2001 to September 2001, the Company will pay interest only, or approximately $2.5 million, and (ii) from October 2001 to March 2002, the Company will make monthly principal and interest payments of $700,000 or a total of $4.2 million. Aquila will evaluate the loan monthly and, at its sole discretion, can discontinue the repayment schedule described above and revert to the requirement of principal payments equal to Defined Cash Flow. Due to Aquila's unilateral ability to modify the repayment schedule described above, the Company has classified $11.7 million of the Aquila debt as current, based on the Company's best estimate of Defined Cash Flow for the year ending December 31, 2001. The Company anticipates the Aquila Credit Agreement will be amended during second quarter 2001 to reflect the changes described above. The Company will continue to seek to increase the amount available under the Aquila Credit Agreement and to revise the repayment requirements. However, there can be no assurance that the Company will be successful in its efforts to further amend the Aquila Credit Agreement. EXHIBIT 10.01 The Mallon Employee Bonus Pool: A Definitive Statement of its Characteristics and Rules (Revised February 1998) Recitals A. As a means of compensating and motivating their employees, Mallon Resources Corporation, a Colorado corporation, and its wholly-owned subsidiary, Mallon Oil Company, a Colorado corporation (collectively, the "Companies"), have since 1988 maintained a compensation plan (the "Plan") pursuant to which they have irrevocably set apart for and allocated to The Mallon Employees Bonus Pool (as hereinafter defined, "Beneficiary") a portion of the gross proceeds derived from the sale of their hydrocarbon production. B. The purpose of this document is to delineate, define, clarify and publish the characteristics of, and rules governing, the Plan. I. Royalty Effective with the organization of Mallon Resources Corporation ("MRC") in December 1988, the Companies established the Plan by declaring and dedicating a portion of the gross proceeds from the sale of any or all of the hydrocarbons produced from any real property interest then owned or thereafter acquired by the Companies were forever irrevocably set apart for, and allocated to, Beneficiary as an unrecorded royalty (the "Royalty"), upon the terms and conditions described as follows: 1. The Royalty is the right to receive an amount equal to 1.3% of the actual cash received as gross revenue generated by the sale of any or all of the Companies' hydrocarbons, free and clear of all costs of development, production, and operation, net only of (a) production taxes, transportation charges, and other similar revenue related burdens incurred with regard to such production, and (b) the effects of hedging and similar arrangements. 2. The Royalty is to be paid over to the Beneficiary not less often than quarterly, within 60 days following the completion of each calendar quarter. 3. The Royalty is intended to be the functional equivalent of a real property right. The Companies' obligation to pay the Royalty is binding upon, and enforceable against, the Companies and their successors and assigns, and all assignments or transfers of interests in any of the Companies' real property interests are to (a) be made expressly subject to the obligation to pay the Royalty, or (b) be made only after a ratable portion of the sales proceeds have been set apart for and allocated to Beneficiary. II. Beneficiary The Mallon Employee Bonus Pool is maintained and administered by the Chairman of the Board of Directors (the "Board") of MRC, in accordance with the following: 1. Monies in the Pool are to be distributed among Qualified Participants (as hereinafter defined) on a quarterly basis, or at such other times as the Chairman shall determine. 2. The amount of money distributed from the pool to a Qualified Participant, if any, is determined in the sole discretion of the Chairman. 3. Qualified Participants are each employee of MRC or any of its subsidiaries. Membership on the Board does not disqualify an employee from being a Qualified Participant. 4. No Participant has any right to receive any money from the Pool, except to the extent determined by the Chairman in his sole discretion. No Participant has any right to assign, alienate, transfer, encumber or anticipate his interest in any benefits under the Pool, nor may any such possible benefits be subject to any legal process to levy upon or attach the same for payment of any claim against any Participant. 5. MRC may withhold taxes with respect to distributions from the Pool if it determines it is (or may be) required to do so under any federal or state law. III. Termination, Amendment, Sale 1. The Plan may not be terminated, amended, sold or modified except with the written consent of the Board, the Chairman, and at least three of the five most senior (by length of employment with MRC) Qualified Participants. 2. Upon a "takeover of MRC," an amount of cash equal to the fair future value of the Royalty shall be immediately paid to Beneficiary for prompt distribution to those who were Qualified Participants immediately prior to the takeover of MRC in accordance with the direction of the Chairman who was in office immediately prior to the takeover of MRC. For the purposes of this section, the term "takeover of MRC" shall mean any of the following: a) The acquisition or ownership of 50% or more of MRC's Common Stock then issued and outstanding by any person or entity, or group of persons or entities, not affiliated with MRC as of the effective date of this document, without the express approval of a majority of the members of Board who are members of the Board as of the effective date of this document or are members of the Board who, after the effective date of this document, were recommended to the shareholders for election to the Board by management of MRC, or b) The election of individuals constituting a majority of the members of the Board who were not either (i) members of the Board as of the date of this document, or (ii) recommended to the shareholders by management of MRC, or c) A legally binding vote of the shareholders of MRC in favor of selling all or substantially all of the assets of MRC. VI. Miscellaneous 1. The Plan has been made under, and is to be construed in accordance with, the laws of the State of Colorado. 2. The Plan was made for the benefit of Beneficiary and is intended to be relied upon by the employees of the Companies as a condition of their employment, and it is intended that its terms as delineated in this document shall be enforceable in a court of law by them. This document has been approved by (a) the Chairman and (b) the employees of MRC noted below (for themselves and as representatives of all of the Qualified Participants) as a true and complete statement of the terms and conditions of the Plan. This document is made to be effective for all purposes as of April 1, 1997 and as a confirmation of the Company's prior practice with respect to the Plan. /s/ George O. Mallon, Jr. /s/ Kevin M. Fitzgerald /s/ Roy K. Ross George O. Mallon, Jr., Chairman Kevin M. Fitzgerald Roy K. Ross /s/ Carolena F. Chapman /s/ Alfonso R. Lopez /s/ Ray E. Jones Carolena F. Chapman Alfonso R. Lopez Ray E. Jones /s/ Donald M. Erickson, Jr. /s/ Randy Stalcup /s/ Wendell A. Bond Donald M. Erickson, Jr. Randy Stalcup Wendell A. Bond END OF EXHIBIT 10.01 EXHIBIT 10.05 Employment Agreement (George O. Mallon, Jr.) THIS AMENDED AND RESTATED EMPLOYMENT AGREEMENT, effective as of January 1, 2000 (and restated to reflect amendments hereto made through March 29, 2001), is between Mallon Resources Corporation, a Colorado corporation (the "Company"), and George O. Mallon, Jr. ("Employee"). 1. Employment. The Company hereby employs Employee and Employee hereby accepts employment from the Company on the terms and conditions set forth in this Agreement. 2. Duties. (a) Employee shall be the Company's Chairman of the Board, Chief Executive Officer and President. Employee's duties shall be those typically performed by management personnel in like positions with companies similar to the Company. Employee shall faithfully and diligently perform such duties, subject to the direction and control of the Company's board of directors (the "Board"). Additionally, Employee shall perform such duties as shall be required by the Bylaws of the Company and such duties as shall be assigned to him from time to time by the Board. (b) Employee shall devote such working time to the business of the Company as may reasonably be required by the nature of the Company's business, from time to time. Employee shall not engage in any other business activity requiring significant personal services by Employee that in the judgment of the Board may conflict with the proper performance of Employee's duties to the Company. 3. Compensation. Employee's compensation shall be as follows: (a) Annual Base Salary. The Company shall pay to Employee a base salary ("Annual Base Salary") at an annual rate of $175,000.00 for each year of this Agreement, as it may be extended. The Annual Base Salary shall be subject to such withholding regulations as are required by law and shall be paid in installments in accordance with the Company's customary payroll. The Company's Compensation Committee (the "Committee") shall review Employee's work periodically (at least annually), and the Committee may, in its sole discretion, increase Employee's Annual Base Salary if it determines such adjustments are merited and consistent with the Company's executive compensation policies, as they may change from time to time. (b) Cash Bonuses. Employee shall be eligible to receive such cash bonuses as may be determined by the Committee, acting in its sole discretion, based upon Employee's performance and the success of the Company. It is intended that any such bonuses may be commensurate with Employee's position with the Company, and that they be generally proportionate to bonuses awarded to other members of the Company's senior management. (c) Stock Compensation. Employee shall be eligible to participate in such of the Company's stock-based compensation plans for which he is otherwise qualified. (d) Miscellaneous. Employee shall be entitled to participate in any insurance plans, hospitalization plans, medical reimbursement plans, profit sharing plans, retirement plans and other employee benefit plans for which Employee is qualified. Nothing in this paragraph shall require the Company to adopt or maintain any such plans. (e) Excise Tax Make-Whole. The Company wishes to make Employee whole for any excise taxes or related interest or penalties incurred by Employee by reason of Employee's receipt of any payment under this Agreement or any other agreement that is determined to be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code or any interest or penalties incurred by Employee with respect to such excise tax. Accordingly, notwithstanding any other provision of this agreement, any payment or distribution made by the Company to Employee or for Employee's benefit, whether under this Agreement or otherwise, is determined by any taxing authority to be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code and/or any similar federal, state or local law, or if any interest or penalties are incurred by Employee with respect to any such excise tax (all such excise taxes, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Company shall pay Employee an additional payment (an "Excise Tax Gross-Up Payment") in an amount such that after payment by Employee of the Excise Tax, Employee retains an amount of the Excise Tax Gross- Up Payment equal to the sum of all taxes, interest and penalties imposed on Employee as a consequence of the payments and/or distributions in relation to which the Excise Tax was imposed. 4. Sick Leave and Vacation. Employee shall be entitled to sick leave and annual vacation as determined from time to time by the Board, consistent with the Company's sick leave and vacation policies, as they may be changed from time to time. 5. Expenses. The Company shall reimburse Employee for all reasonable entertainment, travel and lodging expenses incurred by Employee in connection with the business of the Company, subject, however, to such rules, regulations and record-keeping requirements as may be established from time to time by the Company; and further subject to the limitation that only such expenses as may be deducted by the Company shall be reimbursed. 6. Term. (a) The term of this Agreement shall commence as of the date of this Agreement and shall continue for a period of 36 months from that date. Notwithstanding the foregoing, on the last day of each month during the term of this Agreement through and including December 31, 2002, an additional month shall automatically be added to the term of this Agreement unless written notice to the contrary has been given by the Board to Employee prior to such month-end date. This "evergreen" provision is intended to extend the term of this Agreement so that there are always (until after January 31, 2003) 36 months remaining until expiration of this Agreement. (b) The Company shall have the right to terminate Employee's employment by the Company by not less than 30 days prior written notice. A termination "for cause" shall only be made if a majority of the Board determines that Employee has (1) failed to perform his duties hereunder in a proper and timely manner, and such failure has continued for more than 30 days following written notice in which the deficiencies were detailed with reasonable particularity, (2) materially violated any of the covenants described in paragraph 8, or (3) has been convicted of any felony or any misdemeanor that involves moral turpitude. If Employee is terminated for cause, Employee shall only be entitled to his Annual Base Salary through the date of termination and the Company shall have no further obligations hereunder, including payment of any bonus amount for such applicable year of termination. If the termination is for a reason other than for cause, Employee shall be entitled to receive salary payments at the rate of Employee's then current Annual Base Salary for the balance of the then unexpired term of this Agreement, together with all such bonus amounts as Employee may be entitled to as of the time of Employee's termination. (c) Employee may terminate this Agreement at any time upon not less than 30 days' prior written notice. If Employee terminates this Agreement, Employee shall only be entitled to his Annual Base Salary through the date of termination. The Company shall have no further obligations hereunder, including payment of any bonus amount for such applicable year of termination. (d) Notwithstanding the provisions of paragraphs 6 (b) and (c), upon the occurrence of a Change of Control of the Company (as defined in the Company's Bylaws) Employee may, at his election made within 30 days following consummation of such event, terminate all of his obligations under this Agreement and receive in one cash payment from the Company an amount equal to the lesser of (1) 100% of all Annual Base Salary payments that would otherwise be paid to Employee under this Agreement through-out the then unexpired term of this Agreement, as it may have been extended, or (2) 299% of the Employee's base compensation amount as defined in Section 280(G) of the Internal Revenue Code. (e) Notwithstanding the provisions of paragraphs 6 (b), (c) and (d), upon the occurrence of a Change of Control of the Company (as defined in the Company's Bylaws) that is not supported by a majority of the members of the Board in office immediately prior to the Change of Control, Employee may, at his election made within 30 days following consummation of such event, terminate all of his obligations under this Agreement, and receive in one cash payment from the Company an amount equal to 300% of all Annual Base Salary payments that would otherwise be paid to Employee under this Agreement through- out the then unexpired term of this Agreement, as it may have been extended. 7. Death or Incapacity. If Employee dies or (in the reasonable judgment of the Board) is incapacitated during the term of this Agreement, this Agreement shall terminate immediately and the Company shall pay to Employee or his legal representative the Annual Base Salary that would otherwise be payable to Employee through the last day of the calendar month during which his death or incapacity occurs. 8. Confidentiality. (a) The relationship between the Company and Employee is one of confidence and trust. (b) As used herein, "Confidential Information" means information about the Company's plans, properties, business contacts, business objectives and goals, including information relating to business opportunities and plans, and negotiating strategies and directives with respect to any of the Company's business activities, whether relating to past, present or prospective activities, and in addition including but not limited to any potential purchases or sales, all geological data and maps, all seismic data and maps, all engineering data, reserves calculations and production methods, all oil and gas prospects, whether domestic or foreign. The foregoing shall constitute Confidential Information whether it is known by Employee prior to his employment by the Company, or otherwise. (c) Employee agrees that he shall at no time during the term of his employment by the Company or for a period of three years following the termination of this Agreement disclose any Confidential Information or component thereof to any person, firm or corporation to any extent or for any reason or purpose, or otherwise use any Confidential Information for his own benefit or in any way contrary to the best interest of the Company. 9. Enforcement of Covenants. In addition to any other remedies available to the Company, it shall be entitled to specific performance of the covenants contained in paragraph 8. If the Company is successful in enforcing its rights under this paragraph 9, Employee shall reimburse the Company for all of the costs of such enforcement, including but not limited to reasonable attorney's fees. 10. Survival of Covenants. The provisions of paragraphs 8 and 9 shall survive the termination of Employee's employment by the Company. 11. Notices. All notices under this Agreement shall be delivered by hand or by registered or certified mail and, if intended for Employee, shall be addressed to Employee at the address contained in the Company's personnel records and if intended for the Company, shall be addressed to the Company at its corporate headquarters. All notices shall be effective upon actual delivery if by hand or, if by mail, five days after being deposited in the United States mail, postage prepaid and addressed as required by this paragraph. 12. Miscellaneous Provisions. (a) This Agreement contains the entire agreement between the parties and supersedes all prior agreements, including the Employment Agreement dated effective as of April 1, 1997. This Agreement shall not be amended or otherwise modified in any manner except by an instrument in writing executed by both parties. (b) Neither this Agreement not any rights or duties under this Agreement may be assigned or delegated by either party unless the other party consents in writing. (c) Except as otherwise provided in this Agreement, this Agreement shall be binding upon and inure to the benefit of the parties and their respective heirs, personal representatives, successors and assigns. (d) This Agreement shall be governed by the laws of the State of Colorado. IN WITNESS WHEREOF the parties have executed this Agreement to be effective as of the day and year first above written. Mallon Resources Corporation By: ____________________________ ____________________________ Roy K. Ross, George O. Mallon, Jr. Executive Vice President END OF EXHIBIT 10.05 EXHIBIT 10.06 Employment Agreement (Kevin M. Fitzgerald) THIS AMENDED AND RESTATED EMPLOYMENT AGREEMENT, effective as of January 1, 2000 (and restated to reflect amendments hereto made through March 29, 2001), is between Mallon Resources Corporation, a Colorado corporation (the "Company"), and Kevin M. Fitzgerald ("Employee"). 1. Employment. The Company hereby employs Employee and Employee hereby accepts employment from the Company on the terms and conditions set forth in this Agreement. 2. Duties. (a) Employee shall be the Company's Executive Vice President. Employee's duties shall be those typically performed by management personnel in like positions with companies similar to the Company. Employee shall faithfully and diligently perform such duties, subject to the direction and control of the Company's board of directors (the "Board"). Additionally, Employee shall perform such duties as shall be required by the Bylaws of the Company and such duties as shall be assigned to him from time to time by the Board. (b) Employee shall devote such working time to the business of the Company as may reasonably be required by the nature of the Company's business, from time to time. Employee shall not engage in any other business activity requiring significant personal services by Employee that in the judgment of the Board may conflict with the proper performance of Employee's duties to the Company. 3. Compensation. Employee's compensation shall be as follows: (a) Annual Base Salary. The Company shall pay to Employee a base salary ("Annual Base Salary") at an annual rate of $145,000.00 for each year of this Agreement, as it may be extended. The Annual Base Salary shall be subject to such withholding regulations as are required by law and shall be paid in installments in accordance with the Company's customary payroll. The Company's Compensation Committee (the "Committee") shall review Employee's work periodically (at least annually), and the Committee may, in its sole discretion, increase Employee's Annual Base Salary if it determines such adjustments are merited and consistent with the Company's executive compensation policies, as they may change from time to time. (b) Cash Bonuses. Employee shall be eligible to receive such cash bonuses as may be determined by the Committee, acting in its sole discretion, based upon Employee's performance and the success of the Company. It is intended that any such bonuses may be commensurate with Employee's position with the Company, and that they be generally proportionate to bonuses awarded to other members of the Company's senior management. (c) Stock Compensation. Employee shall be eligible to participate in such of the Company's stock-based compensation plans for which he is otherwise qualified. (d) Miscellaneous. Employee shall be entitled to participate in any insurance plans, hospitalization plans, medical reimbursement plans, profit sharing plans, retirement plans and other employee benefit plans for which Employee is qualified. Nothing in this paragraph shall require the Company to adopt or maintain any such plans. (e) Excise Tax Make-Whole. The Company wishes to make Employee whole for any excise taxes or related interest or penalties incurred by Employee by reason of Employee's receipt of any payment under this Agreement or any other agreement that is determined to be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code or any interest or penalties incurred by Employee with respect to such excise tax. Accordingly, notwithstanding any other provision of this agreement, any payment or distribution made by the Company to Employee or for Employee's benefit, whether under this Agreement or otherwise, is determined by any taxing authority to be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code and/or any similar federal, state or local law, or if any interest or penalties are incurred by Employee with respect to any such excise tax (all such excise taxes, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Company shall pay Employee an additional payment (an "Excise Tax Gross-Up Payment") in an amount such that after payment by Employee of the Excise Tax, Employee retains an amount of the Excise Tax Gross- Up Payment equal to the sum of all taxes, interest and penalties imposed on Employee as a consequence of the payments and/or distributions in relation to which the Excise Tax was imposed. 4. Sick Leave and Vacation. Employee shall be entitled to sick leave and annual vacation as determined from time to time by the Board, consistent with the Company's sick leave and vacation policies, as they may be changed from time to time. 5. Expenses. The Company shall reimburse Employee for all reasonable entertainment, travel and lodging expenses incurred by Employee in connection with the business of the Company, subject, however, to such rules, regulations and record-keeping requirements as may be established from time to time by the Company; and further subject to the limitation that only such expenses as may be deducted by the Company shall be reimbursed. 6. Term. (a) The term of this Agreement shall commence as of the date of this Agreement and shall continue for a period of 36 months from that date. Notwithstanding the foregoing, on the last day of each month during the term of this Agreement through and including December 31, 2002, an additional month shall automatically be added to the term of this Agreement unless written notice to the contrary has been given by the Board to Employee prior to such month-end date. This "evergreen" provision is intended to extend the term of this Agreement so that there are always (until after January 31, 2003) 36 months remaining until expiration of this Agreement. (b) The Company shall have the right to terminate Employee's employment by the Company by not less than 30 days prior written notice. A termination "for cause" shall only be made if a majority of the Board determines that Employee has (1) failed to perform his duties hereunder in a proper and timely manner, and such failure has continued for more than 30 days following written notice in which the deficiencies were detailed with reasonable particularity, (2) materially violated any of the covenants described in paragraph 8, or (3) has been convicted of any felony or any misdemeanor that involves moral turpitude. If Employee is terminated for cause, Employee shall only be entitled to his Annual Base Salary through the date of termination and the Company shall have no further obligations hereunder, including payment of any bonus amount for such applicable year of termination. If the termination is for a reason other than for cause, Employee shall be entitled to receive salary payments at the rate of Employee's then current Annual Base Salary for the balance of the then unexpired term of this Agreement, together with all such bonus amounts as Employee may be entitled to as of the time of Employee's termination. (c) Employee may terminate this Agreement at any time upon not less than 30 days' prior written notice. If Employee terminates this Agreement, Employee shall only be entitled to his Annual Base Salary through the date of termination. The Company shall have no further obligations hereunder, including payment of any bonus amount for such applicable year of termination. (d) Notwithstanding the provisions of paragraphs 6 (b) and (c), upon the occurrence of a Change of Control of the Company (as defined in the Company's Bylaws) Employee may, at his election made within 30 days following consummation of such event, terminate all of his obligations under this Agreement and receive in one cash payment from the Company an amount equal to the lesser of (1) 100% of all Annual Base Salary payments that would otherwise be paid to Employee under this Agreement through-out the then unexpired term of this Agreement, as it may have been extended, or (2) 299% of the Employee's base compensation amount as defined in Section 280(G) of the Internal Revenue Code. (e) Notwithstanding the provisions of paragraphs 6 (b), (c) and (d), upon the occurrence of a Change of Control of the Company (as defined in the Company's Bylaws) that is not supported by a majority of the members of the Board in office immediately prior to the Change of Control, Employee may, at his election made within 30 days following consummation of such event, terminate all of his obligations under this Agreement, and receive in one cash payment from the Company an amount equal to 300% of all Annual Base Salary payments that would otherwise be paid to Employee under this Agreement through- out the then unexpired term of this Agreement, as it may have been extended. 7. Death or Incapacity. If Employee dies or (in the reasonable judgment of the Board) is incapacitated during the term of this Agreement, this Agreement shall terminate immediately and the Company shall pay to Employee or his legal representative the Annual Base Salary that would otherwise be payable to Employee through the last day of the calendar month during which his death or incapacity occurs. 8. Confidentiality. (a) The relationship between the Company and Employee is one of confidence and trust. (b) As used herein, "Confidential Information" means information about the Company's plans, properties, business contacts, business objectives and goals, including information relating to business opportunities and plans, and negotiating strategies and directives with respect to any of the Company's business activities, whether relating to past, present or prospective activities, and in addition including but not limited to any potential purchases or sales, all geological data and maps, all seismic data and maps, all engineering data, reserves calculations and production methods, all oil and gas prospects, whether domestic or foreign. The foregoing shall constitute Confidential Information whether it is known by Employee prior to his employment by the Company, or otherwise. (c) Employee agrees that he shall at no time during the term of his employment by the Company or for a period of three years following the termination of this Agreement disclose any Confidential Information or component thereof to any person, firm or corporation to any extent or for any reason or purpose, or otherwise use any Confidential Information for his own benefit or in any way contrary to the best interest of the Company. 9. Enforcement of Covenants. In addition to any other remedies available to the Company, it shall be entitled to specific performance of the covenants contained in paragraph 8. If the Company is successful in enforcing its rights under this paragraph 9, Employee shall reimburse the Company for all of the costs of such enforcement, including but not limited to reasonable attorney's fees. 10. Survival of Covenants. The provisions of paragraphs 8 and 9 shall survive the termination of Employee's employment by the Company. 11. Notices. All notices under this Agreement shall be delivered by hand or by registered or certified mail and, if intended for Employee, shall be addressed to Employee at the address contained in the Company's personnel records and if intended for the Company, shall be addressed to the Company at its corporate headquarters. All notices shall be effective upon actual delivery if by hand or, if by mail, five days after being deposited in the United States mail, postage prepaid and addressed as required by this paragraph. 12. Miscellaneous Provisions. (a) This Agreement contains the entire agreement between the parties and supersedes all prior agreements, including the Employment Agreement dated effective as of April 1, 1997. This Agreement shall not be amended or otherwise modified in any manner except by an instrument in writing executed by both parties. (b) Neither this Agreement not any rights or duties under this Agreement may be assigned or delegated by either party unless the other party consents in writing. (c) Except as otherwise provided in this Agreement, this Agreement shall be binding upon and inure to the benefit of the parties and their respective heirs, personal representatives, successors and assigns. (d) This Agreement shall be governed by the laws of the State of Colorado. IN WITNESS WHEREOF the parties have executed this Agreement to be effective as of the day and year first above written. Mallon Resources Corporation By: ____________________________ ____________________________ George O. Mallon, Jr., Kevin M. Fitzgerald President END OF EXHIBIT 10.06 EXHIBIT 10.07 Employment Agreement (Roy K. Ross) THIS AMENDED AND RESTATED EMPLOYMENT AGREEMENT, effective as of January 1, 2000 (and restated to reflect amendments hereto made through March 29, 2001), is between Mallon Resources Corporation, a Colorado corporation (the "Company"), and Roy K. Ross ("Employee"). 1. Employment. The Company hereby employs Employee and Employee hereby accepts employment from the Company on the terms and conditions set forth in this Agreement. 2. Duties. (a) Employee shall be the Company's Executive Vice President. Employee's duties shall be those typically performed by management personnel in like positions with companies similar to the Company. Employee shall faithfully and diligently perform such duties, subject to the direction and control of the Company's board of directors (the "Board"). Additionally, Employee shall perform such duties as shall be required by the Bylaws of the Company and such duties as shall be assigned to him from time to time by the Board. (b) Employee shall devote such working time to the business of the Company as may reasonably be required by the nature of the Company's business, from time to time. Employee shall not engage in any other business activity requiring significant personal services by Employee that in the judgment of the Board may conflict with the proper performance of Employee's duties to the Company. 3. Compensation. Employee's compensation shall be as follows: (a) Annual Base Salary. The Company shall pay to Employee a base salary ("Annual Base Salary") at an annual rate of $140,000.00 for each year of this Agreement, as it may be extended. The Annual Base Salary shall be subject to such withholding regulations as are required by law and shall be paid in installments in accordance with the Company's customary payroll. The Company's Compensation Committee (the "Committee") shall review Employee's work periodically (at least annually), and the Committee may, in its sole discretion, increase Employee's Annual Base Salary if it determines such adjustments are merited and consistent with the Company's executive compensation policies, as they may change from time to time. (b) Cash Bonuses. Employee shall be eligible to receive such cash bonuses as may be determined by the Committee, acting in its sole discretion, based upon Employee's performance and the success of the Company. It is intended that any such bonuses may be commensurate with Employee's position with the Company, and that they be generally proportionate to bonuses awarded to other members of the Company's senior management. (c) Stock Compensation. Employee shall be eligible to participate in such of the Company's stock-based compensation plans for which he is otherwise qualified. (d) Miscellaneous. Employee shall be entitled to participate in any insurance plans, hospitalization plans, medical reimbursement plans, profit sharing plans, retirement plans and other employee benefit plans for which Employee is qualified. Nothing in this paragraph shall require the Company to adopt or maintain any such plans. (e) Excise Tax Make-Whole. The Company wishes to make Employee whole for any excise taxes or related interest or penalties incurred by Employee by reason of Employee's receipt of any payment under this Agreement or any other agreement that is determined to be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code or any interest or penalties incurred by Employee with respect to such excise tax. Accordingly, notwithstanding any other provision of this agreement, any payment or distribution made by the Company to Employee or for Employee's benefit, whether under this Agreement or otherwise, is determined by any taxing authority to be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code and/or any similar federal, state or local law, or if any interest or penalties are incurred by Employee with respect to any such excise tax (all such excise taxes, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Company shall pay Employee an additional payment (an "Excise Tax Gross-Up Payment") in an amount such that after payment by Employee of the Excise Tax, Employee retains an amount of the Excise Tax Gross- Up Payment equal to the sum of all taxes, interest and penalties imposed on Employee as a consequence of the payments and/or distributions in relation to which the Excise Tax was imposed. 4. Sick Leave and Vacation. Employee shall be entitled to sick leave and annual vacation as determined from time to time by the Board, consistent with the Company's sick leave and vacation policies, as they may be changed from time to time. 5. Expenses. The Company shall reimburse Employee for all reasonable entertainment, travel and lodging expenses incurred by Employee in connection with the business of the Company, subject, however, to such rules, regulations and record-keeping requirements as may be established from time to time by the Company; and further subject to the limitation that only such expenses as may be deducted by the Company shall be reimbursed. 6. Term. (a) The term of this Agreement shall commence as of the date of this Agreement and shall continue for a period of 36 months from that date. Notwithstanding the foregoing, on the last day of each month during the term of this Agreement through and including December 31, 2002, an additional month shall automatically be added to the term of this Agreement unless written notice to the contrary has been given by the Board to Employee prior to such month-end date. This "evergreen" provision is intended to extend the term of this Agreement so that there are always (until after January 31, 2003) 36 months remaining until expiration of this Agreement. (b) The Company shall have the right to terminate Employee's employment by the Company by not less than 30 days prior written notice. A termination "for cause" shall only be made if a majority of the Board determines that Employee has (1) failed to perform his duties hereunder in a proper and timely manner, and such failure has continued for more than 30 days following written notice in which the deficiencies were detailed with reasonable particularity, (2) materially violated any of the covenants described in paragraph 8, or (3) has been convicted of any felony or any misdemeanor that involves moral turpitude. If Employee is terminated for cause, Employee shall only be entitled to his Annual Base Salary through the date of termination and the Company shall have no further obligations hereunder, including payment of any bonus amount for such applicable year of termination. If the termination is for a reason other than for cause, Employee shall be entitled to receive salary payments at the rate of Employee's then current Annual Base Salary for the balance of the then unexpired term of this Agreement, together with all such bonus amounts as Employee may be entitled to as of the time of Employee's termination. (c) Employee may terminate this Agreement at any time upon not less than 30 days' prior written notice. If Employee terminates this Agreement, Employee shall only be entitled to his Annual Base Salary through the date of termination. The Company shall have no further obligations hereunder, including payment of any bonus amount for such applicable year of termination. (d) Notwithstanding the provisions of paragraphs 6 (b) and (c), upon the occurrence of a Change of Control of the Company (as defined in the Company's Bylaws) Employee may, at his election made within 30 days following consummation of such event, terminate all of his obligations under this Agreement and receive in one cash payment from the Company an amount equal to the lesser of (1) 100% of all Annual Base Salary payments that would otherwise be paid to Employee under this Agreement through-out the then unexpired term of this Agreement, as it may have been extended, or (2) 299% of the Employee's base compensation amount as defined in Section 280(G) of the Internal Revenue Code. (e) Notwithstanding the provisions of paragraphs 6 (b), (c) and (d), upon the occurrence of a Change of Control of the Company (as defined in the Company's Bylaws) that is not supported by a majority of the members of the Board in office immediately prior to the Change of Control, Employee may, at his election made within 30 days following consummation of such event, terminate all of his obligations under this Agreement, and receive in one cash payment from the Company an amount equal to 300% of all Annual Base Salary payments that would otherwise be paid to Employee under this Agreement through- out the then unexpired term of this Agreement, as it may have been extended. 7. Death or Incapacity. If Employee dies or (in the reasonable judgment of the Board) is incapacitated during the term of this Agreement, this Agreement shall terminate immediately and the Company shall pay to Employee or his legal representative the Annual Base Salary that would otherwise be payable to Employee through the last day of the calendar month during which his death or incapacity occurs. 8. Confidentiality. (a) The relationship between the Company and Employee is one of confidence and trust. (b) As used herein, "Confidential Information" means information about the Company's plans, properties, business contacts, business objectives and goals, including information relating to business opportunities and plans, and negotiating strategies and directives with respect to any of the Company's business activities, whether relating to past, present or prospective activities, and in addition including but not limited to any potential purchases or sales, all geological data and maps, all seismic data and maps, all engineering data, reserves calculations and production methods, all oil and gas prospects, whether domestic or foreign. The foregoing shall constitute Confidential Information whether it is known by Employee prior to his employment by the Company, or otherwise. (c) Employee agrees that he shall at no time during the term of his employment by the Company or for a period of three years following the termination of this Agreement disclose any Confidential Information or component thereof to any person, firm or corporation to any extent or for any reason or purpose, or otherwise use any Confidential Information for his own benefit or in any way contrary to the best interest of the Company. 9. Enforcement of Covenants. In addition to any other remedies available to the Company, it shall be entitled to specific performance of the covenants contained in paragraph 8. If the Company is successful in enforcing its rights under this paragraph 9, Employee shall reimburse the Company for all of the costs of such enforcement, including but not limited to reasonable attorney's fees. 10. Survival of Covenants. The provisions of paragraphs 8 and 9 shall survive the termination of Employee's employment by the Company. 11. Notices. All notices under this Agreement shall be delivered by hand or by registered or certified mail and, if intended for Employee, shall be addressed to Employee at the address contained in the Company's personnel records and if intended for the Company, shall be addressed to the Company at its corporate headquarters. All notices shall be effective upon actual delivery if by hand or, if by mail, five days after being deposited in the United States mail, postage prepaid and addressed as required by this paragraph. 12. Miscellaneous Provisions. (a) This Agreement contains the entire agreement between the parties and supersedes all prior agreements, including the Employment Agreement dated effective as of April 1, 1997. This Agreement shall not be amended or otherwise modified in any manner except by an instrument in writing executed by both parties. (b) Neither this Agreement not any rights or duties under this Agreement may be assigned or delegated by either party unless the other party consents in writing. (c) Except as otherwise provided in this Agreement, this Agreement shall be binding upon and inure to the benefit of the parties and their respective heirs, personal representatives, successors and assigns. (d) This Agreement shall be governed by the laws of the State of Colorado. IN WITNESS WHEREOF the parties have executed this Agreement to be effective as of the day and year first above written. Mallon Resources Corporation By: ____________________________ ____________________________ George O. Mallon, Jr., Roy K. Ross President END OF EXHIBIT 10.07 EXHIBIT 10.08 Peter H. Blum Bear Ridge Capital LLC 4 Trapping Way Pleasantville, NY 10570 Dear Peter: The purpose of this letter is to restate and confirm the terms upon which Bear Ridge Capital LLC ("BRC") will provide professional financial consulting services to Mallon Resources Corporation ("Mallon"). Mallon understands that BRC and Mallon have agreed to the following terms: 1. Term. This agreement shall be effective from January 1, 2001, through December 31, 2001. The parties agree to review the nature and terms of the contract in December 2001, and will mutually agree to appropriate adjustments or termination depending on the results of BRC's efforts. Either party, at any time, may terminate this agreement by giving the other party written notice at least 30 days prior to the effective date of termination. During the notice period, all other rights and duties of the parties under this agreement shall continue. If either Mallon or BRC desires to terminate work in process commenced before receipt of termination, it may do so upon mutual consent of the parties. 2. Services. BRC shall provide professional financial consulting services to Mallon. The services shall include advice and negotiating services with respect to merger, acquisition and sale opportunities; advice concerning the nature, timing and content of communications to the brokerage industry; advice concerning brokerage industry services and service providers; and advice concerning when and how to access the capital markets. In providing these services, BRC shall be subject to the reasonable supervision and direction of Mallon's Chief Executive Officer. Notwithstanding the foregoing, BRC is intended to be a part-time independent contractor to Mallon, not an employee of Mallon. It is expected that BRC will devote all such time to the performance of its obligations under this agreement as may reasonably be required. 3. Cash Compensation. BRC shall be paid $11,000 per month. Payments will be made monthly, in arrears, on the last day of each month. 4. Stock Option Adjustment. Under a separate agreement and pursuant to the terms of the letter agreement dated January 25, 2000, Mallon issued to BRC warrants to purchase an aggregate 40,000 shares of Mallon's $0.01 par value common stock. One of the options granted, covering 20,000 shares, only vests "upon a Change of Control of Mallon in a transaction in which, on a fully diluted basis, shares of Mallon's common stock are valued at a price in excess of $11.50 per share." That language in that option is hereby changed read "upon a Change of Control of Mallon in a transaction in which, on a fully diluted basis, shares of Mallon's common stock are valued (as of the date upon which the transaction is first contracted for) at a price in excess of $7.99 per share." 5. Bonus. BRC will be eligible to receive bonus payments, from time to time, upon the same basis as other members of management. Such payments, if any, will be determined by the Compensation Committee of Mallon's board of directors. No such payments are required to be made. 6. Expenses. BRC shall be reimbursed for its reasonable travel and out-of- pocket expenses incurred in performance of its services under this agreement, subject to BRC's compliance with Mallon's standard requirements for expense reimbursements. 7. Governing Law. The validity, interpretation, and performance of this letter agreement shall be controlled by and construed under the laws of the State of Colorado. If the foregoing accurately sets forth your understanding of our agreement, please execute and return a copy of this letter, whereupon it shall reflect an agreement between the parties. Very truly yours, Mallon Resources Corporation By: ________________________________ George O. Mallon, Jr. Chairman Accepted and Agreed to: Bear Ridge Capital LLC By: ________________________________ Peter H. Blum, President END OF EXHIBIT 10.08 EXHIBIT 10.16 Promissory Note Amendment THIS PROMISSORY NOTE AMENDMENT, dated as of October 20, 2000, (i) is between Mallon Resources Corporation, a Colorado corporation ("Holder"), and George O. Mallon, Jr. ("Maker"); and (ii) relates to that certain promissory note dated September 2, 1999, from Maker to Holder in the original principal amount of $1,585,018.00 (the "Note"). Agreements For good and valuable consideration, and in order to amend certain of the Note's terms, the parties have executed this Promissory Note Amendment and caused an original executed copy of this Agreement to be attached to the original Note. The terms of the original Note are hereby amended in the following respects: 1. The Due Date. The principal and all accrued interest on the Note shall be due in payable in one payment due on August 31, 2004. 2. Cancellation of Note. Upon the occurrence of any change in control of Holder (as defined in holder's Bylaws), or the death or disability of Maker, all unpaid principal of the Note and all accrued but unpaid interest then due on the Note shall automatically be cancelled and forgiven, and the Note shall thereafter be considered as paid in full and of no further force and effect. In witness whereof, this Promissory Note Amendment has been entered into as of October 20, 2000. Maker: Holder: Mallon Resources Corporation __________________________ George O. Mallon, Jr. By: _________________________ Roy K. Ross, Executive Vice President General Counsel END OF EXHIBIT 10.16 EXHIBIT 10.17 Promissory Note Amendment THIS PROMISSORY NOTE AMENDMENT, dated as of October 20, 2000, (i) is between Mallon Resources Corporation, a Colorado corporation ("Holder"), and Kevin M. Fitzgerald ("Maker"); and (ii) relates to that certain promissory note dated September 2, 1999, from Maker to Holder in the original principal amount of $645,548.75 (the "Note"). Agreements For good and valuable consideration, and in order to amend certain of the Note's terms, the parties have executed this Promissory Note Amendment and caused an original executed copy of this Agreement to be attached to the original Note. The terms of the original Note are hereby amended in the following respects: 1. The Due Date. The principal and all accrued interest on the Note shall be due in payable in one payment due on August 31, 2004. 2. Cancellation of Note. Upon the occurrence of any change in control of Holder (as defined in holder's Bylaws), or the death or disability of Maker, all unpaid principal of the Note and all accrued but unpaid interest then due on the Note shall automatically be cancelled and forgiven, and the Note shall thereafter be considered as paid in full and of no further force and effect. In witness whereof, this Promissory Note Amendment has been entered into as of October 20, 2000. Maker: Holder: Mallon Resources Corporation __________________________ Kevin M. Fitzgerald By: _________________________ George O. Mallon, Jr., CEO & President END OF EXHIBIT 10.17 EXHIBIT 10.18 Promissory Note Amendment THIS PROMISSORY NOTE AMENDMENT, dated as of October 20, 2000, (i) is between Mallon Resources Corporation, a Colorado corporation ("Holder"), and Roy K. Ross ("Maker"); and (ii) relates to that certain promissory note dated September 2, 1999, from Maker to Holder in the original principal amount of $391,283.75 (the "Note"). Agreements For good and valuable consideration, and in order to amend certain of the Note's terms, the parties have executed this Promissory Note Amendment and caused an original executed copy of this Agreement to be attached to the original Note. The terms of the original Note are hereby amended in the following respects: 1. The Due Date. The principal and all accrued interest on the Note shall be due in payable in one payment due on August 31, 2004. 2. Cancellation of Note. Upon the occurrence of any change in control of Holder (as defined in holder's Bylaws), or the death or disability of Maker, all unpaid principal of the Note and all accrued but unpaid interest then due on the Note shall automatically be cancelled and forgiven, and the Note shall thereafter be considered as paid in full and of no further force and effect. In witness whereof, this Promissory Note Amendment has been entered into as of October 20, 2000. Maker: Holder: Mallon Resources Corporation __________________________ Roy K. Ross By: _________________________ George O. Mallon, Jr., CEO & President END OF EXHIBIT 10.18 EXHIBIT 10.19 February 2, 2000 Mr. George O. Mallon, Jr. 999 - 18th Street, Suite 1700 Denver, Colorado 80202 Re: Overriding Royalty Interest in Costa Rica Hydrocarbon Contracts Dear Mr. Mallon: This letter (this "Agreement") will set forth the agreement between Mallon Resources Corporation ("MRC") and you ("Mallon") with regard to certain overriding royalty interests in hydrocarbon contracts to be acquired by MRC or its Affiliates in Costa Rica. In consideration of the mutual promises set forth herein and other good and valuable consideration the receipt and sufficiency of which is hereby acknowledged, MRC and Mallon hereby agree as follows: 1. Board Approval. The execution and delivery of this Agreement by MRC has been authorized by the Board of Directors of MRC, which authorization is evidenced by a Consent of Directors of MRC executed effective as of January 1, 2000, a copy of which is attached hereto as Exhibit A. 2. Hydrocarbon Contracts. By a Bid Announcement dated November 2, 1999 (the "Bid Announcement") the Costa Rica Ministry of Environment and Energy (the "Ministry") solicited bids for contracts for the exploration and exploitation of hydrocarbons ("Hydrocarbon Contracts") to be issued pursuant to Chapter VI of the Hydrocarbons Law of the Republic of Costa Rica (Act of Congress Number 7399, April 27, 1994) (the "Hydrocarbon Law") and the regulations of the Ministry concerning the bidding system for Hydrocarbon Contracts dated January 22, 1997 (the "Bidding Regulations"). Pursuant to the Bid Announcement and the Bidding Regulations MRC and/or certain of its Affiliates have submitted bid offers for Hydrocarbon Contracts covering Exploration Blocks 5 through 11, as outlined in orange on the plat attached hereto as Exhibit B, which Exploration Blocks are more particularly described in the Bid Announcement. In addition to Exploration Blocks 5 through 11, MRC or its Affiliates may acquire Hydrocarbon Contracts covering other Exploration Blocks pursuant to future bid announcements. MRC or its Affiliates also may acquire through farmout agreements or other agreements all or an undivided interest in Hydrocarbon Contracts covering other Exploration Blocks that have been awarded or may be awarded in the future to third parties pursuant to the Bid Announcement or future bid announcements. For purposes of this Agreement an "Affiliate" of MRC shall mean (i) any person directly or indirectly controlled by, controlling or under common control with MRC and (ii) any shareholder, director or officer of MRC or of any person referred to in clause (i) above. For the purposes of this definition "control" of any person means (a) with respect to any corporation or other person having voting shares or the equivalent and elected directors, managers, or persons performing similar functions, the ownership or power to vote, directly or indirectly shares or the equivalent representing 50% or more of the power to vote in the election of directors, managers, or persons performing similar functions, (b) ownership of 50% or more of the equity or beneficial interest in any other entity and (c) the ability to direct the business and affairs of any person by acting as a general partner, manager or otherwise. 3. Royalty Interest. MRC hereby agrees to execute and deliver, and to cause any of its Affiliates to execute and deliver, to Mallon an assignment and conveyance, in form acceptable to Mallon and its Costa Rican counsel, of an overriding royalty interest in all hydrocarbons produced, saved and marketed from any of the Exploration Blocks described in Exhibit B or any other Exploration Blocks in Costa Rica as to which a Hydrocarbon Contract is either (a) awarded directly to MRC or any of its Affiliates pursuant to the Bid Announcement or any future bid announcements from the Ministry or (b) subsequently acquired in whole or in part by MRC or any of its Affiliates by way of farmout or other agreement from third parties who acquired such Hydrocarbon Contract under the Bid Announcement or other bid announcements. The overriding royalty interests in all such Hydrocarbon Contracts are collectively called the "Royalty Interest." The terms of the Royalty Interest shall be as set forth in the Terms of Overriding Royalty Interest set forth in Exhibit C attached hereto. The assignment and conveyance of the Royalty Interest shall be executed and delivered by MRC (and/or any of its Affiliates that obtain an interest in any Hydrocarbon Contracts subject to this Agreement) within 10 days after (c) the final award by the Ministry to such entity of any Hydrocarbon Contract and the execution and delivery of such Hydrocarbon Contract by the Ministry and such entity or (d) the acquisition by MRC and/or any of its Affiliates of the entire or an undivided interest in any Hydrocarbon Contract awarded by the Ministry to a third party. 4. Property Interest; Government Approvals. The intent of the parties is that the Royalty Interest, to the extent allowed under the Hydrocarbon Law or other laws of Costa Rica, shall constitute a real property interest in and to the percentage described in Exhibit C of the hydrocarbons produced, saved and marketed under the terms of a Hydrocarbon Contract from any Exploration Block that is subject to the Royalty Interest, and the parties intend that the Royalty Interest is not merely the contractual obligation of MRC under this Agreement to pay such percentage of hydrocarbon proceeds to Mallon. The parties accordingly agree to use all reasonable business efforts to have the assignment of the Royalty Interest approved and recognized by the Ministry or other appropriate agency on behalf of the Republic of Costa Rica. If, however, recognition of the Royalty Interest as a real property interest is not allowed under Costa Rican law or if for any other reason such approval of the Ministry can not be obtained, then the parties agree that the Royalty Interest shall constitute a property interest of Mallon under Colorado law in and to hydrocarbons produced, saved and marketed from the Exploration Blocks subject hereto, shall not be a mere contractual obligation of MRC to pay hydrocarbon proceeds, and the parties shall take all reasonable actions necessary to confirm such treatment for Colorado law purposes. 5. Assignment. Mallon's rights to the Royalty Interest under paragraph 3 shall be binding on all successors and assigns of MRC or any of its Affiliates and shall burden any Hydrocarbon Contracts subject to paragraph 3. Any assignments or other transfers by MRC or any of its Affiliates of all or any portion of their rights or interests in and to any Exploration Blocks or Hydrocarbon Contracts that are subject to Mallon's rights under paragraph 3 above shall be made expressly subject to the terms of this Agreement and to the Royalty Interest. Mallon's rights under this Agreement and in and to the Royalty Interest shall be freely assignable. 6. Arbitration. (a) Disputes between the parties arising out of or in connection with this Agreement or the interpretation of this Agreement shall be finally and conclusively settled by binding arbitration before the American Arbitration Association (the "AAA"), under the International Rules of Arbitration of the AAA then in effect (except as specifically modified by this section) before an arbitral tribunal consisting of three (3) neutral arbitrators (the "Arbitral Tribunal") appointed in accordance with such Rules. The arbitration shall be conducted in the English language and shall take place in Denver, Colorado. All decisions of the Arbitral Tribunal shall be final and binding on the parties and may be entered against them in a court of competent jurisdiction. The Arbitral Tribunal shall determine the costs of arbitration in its award, and such costs shall be allocated between the parties as determined by the Arbitral Tribunal, provided, however, that any costs, fees or taxes incidental to enforcing the arbitral award shall, to the maximum extent permitted by applicable law, be borne by the party resisting such enforcement. Unless otherwise provided in this Agreement, neither the existence of any dispute, controversy or claim, nor the fact that arbitration is pending hereunder, shall relieve any party of its obligations under this Agreement. (b) Each of the parties hereby agrees that any judgment rendered by the arbitrators against it and entered in any court of record in Denver, Colorado, may be executed against its assets in any jurisdiction. By its signature on this Agreement, each of the parties hereby irrevocably submits to the non- exclusive jurisdiction of the appropriate courts in Denver, Colorado or any such other jurisdictions in any legal action or proceeding relating to such execution of judgment. Each of the parties hereby designates the AAA as its agent to receive, for and on its behalf, service of process in Denver, Colorado, in any legal action or proceeding relating to such execution. Each of the parties irrevocably consents to the service of process out of Colorado courts in any such action or proceeding by personal delivery by courier service or by the mailing of copies thereof by registered mail, postage prepaid, to it. The foregoing, however, shall not limit the right of any party to serve process in any other manner permitted by Colorado law or to commence any legal action or proceeding or to obtain execution of judgment in any appropriate jurisdiction. Each of the parties hereby irrevocably waives, to the fullest extent permitted by any applicable law, any objection which it may now have to any suit, action or proceeding arising out of or relating to the enforcement of an arbitral judgment under this Agreement being brought in the United States of America or in any other jurisdiction in which it has assets, and hereby further irrevocably waives any claim that any such suit, action or proceeding brought in any such jurisdiction has been brought in an inconvenient forum. (c) With this arbitration provision the parties do not intend to deprive any court of its jurisdiction to issue a prearbitral injunction, prearbitral attachment or other preliminary remedy in aid of arbitration proceedings and enforcement of the award. 7. Governing Law. This Agreement and any arbitration or dispute resolution conducted pursuant thereto shall be construed in accordance with, and governed by, the laws of the State of Colorado, except as to matters necessarily governed by the laws of Costa Rica pertaining to the Royalty Interest. 8. Entire Agreement. This Agreement constitutes the entire understanding among the parties with respect to the subject matter hereof, superseding all negotiations, prior discussions and prior agreements. 9. Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of, the parties hereto, and their respective successors and assigns. If the foregoing accurately sets forth our agreement, please so indicate by executing this Agreement in the space provided below. Very truly yours, MALLON RESOURCES CORPORATION By:_________________________________ Kevin M. Fitzgerald, President ACCEPTED AND AGREED TO this ____ day of February, 2000: ___________________________ George O. Mallon, Jr. Exhibit C TERMS OF OVERRIDING ROYALTY INTEREST This Exhibit C is attached to and made a part of that certain letter agreement dated February 2, 2000 (the "Agreement") between Mallon Resources Corporation ("MRC") and George O. Mallon, Jr. ("Mallon"). Capitalized terms not otherwise defined herein shall have the meaning set forth in the Agreement. The principal terms of the Royalty Interest shall be as follows: 1. MRC and any of its Affiliates receiving an interest in a Hydrocarbon Contract shall assign and convey to Mallon, his successors and assigns, overriding royalty interests equal to an undivided 3% of 8/8ths of the value of all oil, gas and other hydrocarbons and minerals produced, saved and marketed from all lands (including without limitation, all depths, horizons, formations and zones) included in the Exploration Blocks subject to the Agreement under and pursuant to the terms and provisions of the Hydrocarbon Contracts subject to the Agreement. 2. For purposes of paragraph 1, the value of oil, gas and other hydrocarbons shall be determined as follows: (a) for any oil and liquid hydrocarbons recovered at the well, the greater of the market value at the Exploration Block or the amount realized from the sale of such oil and liquid hydrocarbons; (b) for gas used by MRC off the Exploration Block for other than electricity generation, the market value of such gas at the point so used; (c) for gas used by MRC either on or off the Exploration Block for the generation of electricity delivered into the power grid of Costa Rica or sold by MRC to a third party for such purpose, the value of the gas shall be the greater of (i) the market value of such gas at the point of sale or use, or (ii) the market value of the electricity produced by the use of such gas; (d) for gas that is sold by MRC for other than electricity generation, but not processed, the market value at the inlet of the market pipeline to which such gas is delivered; and (e) for gas sold by MRC and delivered for processing, the market value of the residue gas at the tailgate of the plant to which the gas is delivered (or the value of such gas under clause (c) if it is used in electricity generation), plus the market value at the plant of the products recovered when such gas is processed; provided that in the event gas, including gas from oil wells, is processed in any facility or plant in which MRC, or any Affiliate of MRC, has, directly or indirectly, an ownership or operating interest, then the value of such gas shall not be less than: (x) the combined values at the plant of all products extracted therefrom and the residue gas, (y) the market value of such gas (including value calculated under clause (c) if such gas is used in electricity generation), or (z) the value MRC is receiving for its production, whichever value is greater; and provided further that the royalty shall never be based on an amount realized from such sale that is less than the amount which MRC is receiving for its production. For avoidance of doubt, royalty is to be paid on all payments received by MRC under or as a result of a gas purchase contract, including, but not limited to, reservation charges and, when gas for which payment has been made earlier is eventually produced, take-or-pay or contract settlement proceeds and amount paid for gas not taken. For purposes of this paragraph, references to MRC shall include references to MRC, its Affiliates and their successors and assigns. 3. The Royalty Interest shall not be paid upon oil, gas or other hydrocarbons used for operating, development or production purposes on the Exploration Block, provided that such hydrocarbons so used shall not exceed 5% of the total production, and further provided that the exclusion from the Royalty in this paragraph 3 shall not apply to the use of gas for generation of electricity into the Costa Rica power grid. 4. If the interest acquired by MRC or any of its Affiliates in any Hydrocarbon Contract is less than 100%, then the Royalty Interest shall be reduced in the proportion that the interest of MRC or its Affiliates in that Hydrocarbon Contract bears to 100%. 5. Except as otherwise provided in this Exhibit C, the Royalty Interest shall be treated, computed, calculated and paid or delivered to Mallon in a like manner and under the same terms and conditions as the royalties reserved to the Republic of Costa Rica and local governments under each Hydrocarbon Contract, mutatis mutandis. Notwithstanding the immediately preceding sentence or the provisions of the Hydrocarbon Contracts, the Royalty Interest shall be free and clear of any and all costs and expenses of drilling, development, production, operation and marketing thereof (including costs and expenses of dehydrating, treating, transporting, boosting, compressing or otherwise processing the oil, gas and other hydrocarbons and minerals in order to make the same marketable), except taxes applicable to said Royalty Interest and the production or income therefrom. 6. The Royalty Interest shall cover any and all oil, gas and minerals of whatever kind or character produced under the terms of the Hydrocarbon Contracts. The Royalty Interest shall automatically burden, attach and be applied to and payable out of and from and encumber any new Hydrocarbon Contracts or any extension, renewal or replacement of the Hydrocarbon Contracts covering the land included in the Exploration Blocks that are obtained on or before two years after the release or other termination of the Hydrocarbon Contract to which the new contract, extension, renewal or replacement relates. 7. MRC shall warrant and forever defend the title of Mallon to the Royalty Interest from and against any and all liens, security interests, encumbrances, defects, burdens and claims arising by, through or under MRC, its Affiliates, or their predecessors in title to any Hydrocarbon Contract. Mallon shall have full right of substitution and subrogation in and to all covenants of warranty given or made with respect to the Hydrocarbon Contracts by the predecessors in title of MRC or its Affiliates to any Hydrocarbon Contract. 8. If MRC at any time elects to abandon or relinquish any Hydrocarbon Contract subject to the Royalty Interest it shall first give Mallon 45 days prior written notice of such election, and Mallon shall have the option, exercisable by written notice within 60 days after its receipt of such notice from MRC, to receive an assignment of such Hydrocarbon Contract from MRC, free and clear of all costs, expenses and obligations arising prior to the date of the assignment to Mallon. 9. Should MRC desire to sell all or any part of its interests in any Hydrocarbon Contract, it shall promptly give written notice to Mallon, with full information concerning its proposed disposition, which shall include the name and address of the prospective transferee (who must be ready, willing and able to purchase), the purchase price, a legal description sufficient to identify the property, and all other terms of the offer. Mallon shall then have an optional prior right, for a period of ten (10) days after the notice is delivered, to purchase for the stated consideration on the same terms and conditions the interest which MRC proposes to sell. However, there shall be no preferential right to purchase in those cases where MRC wishes to mortgage its interests, or to transfer title to its interests to its mortgagee in lieu of or pursuant to foreclosure of a mortgage of its interests, or to dispose of its interests by merger, reorganization, consolidation or by sale of all or substantially all of its oil and gas assets to any party, or by transfer of its interests to a subsidiary or parent company or to a subsidiary of a parent company, or to any company in which such party owns a majority of the stock. END OF EXHIBIT 10.19 EXHIBIT 10.20 (MEMO) From: GOMallon, Chairman To: File Re: Kevin Fitzgerald's ORRI E. Blanco Prospect Rio Arriba County, New Mexico Dated: October 19, 1998 In May 1983, Mallon Oil Company granted Kevin Fitzgerald an overriding royalty interest burdening all acreage it acquired in the above-captioned area, as well as other areas, as a part of his employment contract. The ORRI is equal to 1% of Mallon's net working interest in the acreage, as it may vary from time to time. Exhibit "A" depicts, in yellow, the acreage presently owned by Mallon. The lands outlined in red are lands that were once a part of Mallon's prospects (and subject to exploration agreements), but in which Mallon currently has no interest. Exhibit "B" lists the Prospect Agreements on which Kevin once had an ORRI. At its meeting held May 28, 1998, the Board of Directors of Mallon Resources Corporation duly passed the following resolution: Resolved that, with respect to all lands in which the Company acquires an interest that formerly were burdened with overriding royalty interests for the benefit of Mr. Fitzgerald, that, effective as of the later to occur of July 1, 1998 or the date of acquisition by the Company, Mr. Fitzgerald be granted an overriding royalty interest burdening such land equivalent in size and terms to the overriding royalty interest formerly held by Mr. Fitzgerald. Resolved that, effective as of the later to occur of July 1, 1998 or the date of acquisition by the Company, Mr. Fitzgerald's overriding royalty interests on existing Company acreage extend to and burden all additional interests in the same acreage that the Company may acquire from other parties. The lands covered by the foregoing resolution are those reflected on Exhibits "A" and "B" to this memorandum. The ORRI is to be calculated by multiplying 1% by Mallon's working interest in acquired leases minus the basic royalty interest. If Mallon makes subsequent acquisitions within the acreage already owned, the ORRI will be applied to Mallon's resulting working interest percentage. If Mallon's working interest percentage is reduced as the result of a back-in or non-consent election, the ORRI will be proportionately reduced. Mallon Resources Corporation By: _________________________ George O. Mallon, Jr., Chairman EXHIBIT "B" Boulderado Prospect Farmout Agreement from Union Oil Company of California to Mallon Oil Company dated January 16, 1987 covering the following lands: T28N-R1W, Rio Arriba Co., New Mexico Sections 3, 4, 5, 6, 7, 8, 9, 10, 15, 16, 17, 18, 19, 20, 21, 22, 27, 28, 29, 30, 31, 32, 33, 34 T28N-R2W, Rio Arriba Co., New Mexico Sections 1, 2, 11, 12, 13, 14, 23, 24, 25, 26, 35, 36 T29N-R1W, Rio Arriba Co., New Mexico Sections 27, 28, 29, 30, 31, 32, 33, 34 T29N-R2W, Rio Arriba Co., New Mexico Sections 25, 26, 35, 36 Burns Ranch Prospect Farmout Agreement from Southland Royalty Company to Mallon Oil Company dated September 5, 1986 covering the following lands: T30N-R3W, Rio Arriba Co., New Mexico Sections 1-26, 29-32, 35, 36 Little Flower Prospect Farmout Agreement from Union Oil Company of California to Mallon Oil Company dated May 18, 1987 covering the following lands: T30N-R2W, Rio Arriba Co., New Mexico Sections 1-16, 21-36 Carracas Canyon Prospect Mineral Development Agreement Number ###-##-#### from the Jicarilla Apache Tribe to Robert L. Bayless, Inc. dated August 6, 1990 covering the following lands: T31N-R3W, Rio Arriba Co., New Mexico Sections 1-36 T30N-R3W, Rio Arriba Co., New Mexico Sections 27, 28, 33, 34 High Ridge Prospect Farmout Agreement from Amoco Production Company to Mallon Oil Company covering the following lands: T30N-R2W, Rio Arriba Co., New Mexico Sections 18, 19, 28, 29 END OF EXHIBIT 10.20 11 -----END PRIVACY-ENHANCED MESSAGE-----