10-K 1 0001.txt FORM 10-K 2000 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K [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: 1-10662 ------- Cross Timbers Oil Company (Exact name of registrant as specified in its charter)
Delaware 75-2347769 810 Houston Street, Suite 2000, Fort Worth, Texas 76102 ------------------------------- ------------------- --------------------------------------------------- ------- (State or other jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code) incorporation or organization) Identification No.)
Registrant's telephone number, including area code (817) 870-2800 -------------- Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered ------------------------------------------------- ----------------------------------------- Common Stock, $.01 par value, including preferred New York Stock Exchange stock purchase rights
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) 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. Yes X No ----- ----- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to be the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. _____ Aggregate market value of the Common Stock held by nonaffiliates of the Registrant as of March 16, 2001 was approximately $2,045,000,000 Number of Shares of Common Stock outstanding as of March 1, 2001 - 81,230,051 DOCUMENTS INCORPORATED BY REFERENCE (To The Extent Indicated Herein) Part III of this Report is incorporated by reference from the Registrant's definitive Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 2001. ================================================================================ CROSS TIMBERS OIL COMPANY 2000 ANNUAL REPORT ON FORM 10-K TABLE OF CONTENTS
Item Page ---- ---- Part I 1. and 2. Business and Properties................................................... 1 3. Legal Proceedings......................................................... 15 4. Submission of Matters to a Vote of Security Holders....................... 16 Part II 5. Market for Registrant's Common Equity and Related Stockholder Matters..... 17 6. Selected Financial Data................................................... 18 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................................. 20 7A. Quantitative and Qualitative Disclosures about Market Risk................ 28 8. Financial Statements and Supplementary Data............................... 31 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................................. 31 PART III 10. Directors and Executive Officers of the Registrant........................ 31 11. Executive Compensation.................................................... 31 12. Security Ownership of Certain Beneficial Owners and Management............ 31 13. Certain Relationships and Related Transactions............................ 31 Part IV 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 32
PART I Items 1. and 2. Business and Properties General Cross Timbers Oil Company and its subsidiaries ("the Company") are engaged in the acquisition, development, exploitation and exploration of producing oil and gas properties, and in the production, processing, marketing and transportation of oil and natural gas. The Company has grown primarily through acquisitions of proved oil and gas reserves, followed by development and exploitation activities and strategic acquisitions of additional interests in or near such acquired properties. Growth for the next year or more is expected to be primarily internally generated and will be supplemented by incremental acquisitions. The Company's proved reserves are principally located in relatively long- lived fields with well-established production histories concentrated in the East Texas Basin, the Arkoma Basin of Arkansas and Oklahoma, the San Juan Basin of northwestern New Mexico, the Hugoton Field of Oklahoma and Kansas, the Anadarko Basin of Oklahoma, the Green River Basin of Wyoming, the Permian Basin of West Texas and New Mexico, the Middle Ground Shoal Field of Alaska's Cook Inlet and the Colquitt and Oaks Fields of Louisiana. The Company's estimated proved reserves at December 31, 2000 were 58.4 million barrels ("Bbls") of oil, 1.8 trillion cubic feet ("Tcf") of natural gas and 22 million Bbls of natural gas liquids, based on December 31, 2000 prices of $25.49 per Bbl for oil, $9.55 per thousand cubic feet ("Mcf") for gas and $26.33 per Bbl for natural gas liquids. Approximately 76% of December 31, 2000 proved reserves, computed on a gas energy equivalent ("Mcfe") basis, were proved developed reserves. Increased proved reserves during 2000 were primarily the result of development and exploitation activities, partially offset by production and property sales. During 2000, the Company's daily average production was 12,941 Bbls of oil, 343,871 Mcf of gas and 4,430 Bbls of natural gas liquids. Fourth quarter 2000 daily average production was 12,852 Bbls of oil, 366,007 Mcf of gas and 4,523 Bbls of natural gas liquids. The Company's properties have relatively long reserve lives and highly predictable production profiles. Based on December 31, 2000 proved reserves and projected 2001 production, the average reserve-to-production index of the Company's proved reserves is 14.4 years. In general, the Company's properties have extensive production histories and production enhancement opportunities. While the properties are geographically diversified, the major producing fields are concentrated within core areas, allowing for substantial economies of scale in production and cost-effective application of reservoir management techniques gained from prior operations. As of December 31, 2000, the Company owned interests in 6,885 gross (3,609 net) wells and operated wells representing 92% of the present value of cash flows before income taxes (discounted at 10%) from estimated proved reserves. The high proportion of operated properties allows the Company to control expenses, capital allocation and the timing of development and exploitation activities in its fields. The Company has generated a substantial inventory of approximately 1,500 potential development drilling locations within its existing properties (of which 684 have been attributed proved undeveloped reserves), to support future net reserve additions. The Company estimates net potential reserves related to unbooked development drilling locations to exceed 1.7 Tcf equivalent. The Company's drilling plans are dependent upon product prices and the availability of drilling equipment. The Company employs a disciplined acquisition program refined by senior management to augment its core properties and expand its reserve base. Its engineers and geologists use their expertise and experience gained through the management of existing core properties to target properties to be acquired with similar geological and reservoir characteristics. The Company operates gas gathering systems in East Texas, the Arkoma Basin of Arkansas and Oklahoma, the Hugoton Field of Kansas and Oklahoma and Major County, Oklahoma. The Company also operates a gas processing plant in the Hugoton Field. The Company's gas gathering and processing operations are only in areas where the Company has production and are considered activities which add value to the Company's natural gas production and sales operation. 1 Most of the Company's production is sold at current market prices. The Company markets its gas production and the gas output of its gathering and processing systems. A large portion of natural gas is processed and the resultant natural gas liquids are marketed by unaffiliated third parties. The Company uses fixed price physical sales contracts and futures, forward sales contracts and other price risk management instruments to hedge pricing risks. See "Delivery Contracts" and Part II, Item 7A. History of the Company The Company was incorporated in Delaware in 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986 through 1989. The Company completed its initial public offering of common stock in May 1993. During 1991, the Company formed Cross Timbers Royalty Trust by conveying a 90% net profits interest in substantially all of the royalty and overriding royalty interests then owned in Texas, New Mexico and Oklahoma, and a 75% net profits interests in seven nonoperated working interest properties in Texas and Oklahoma. Cross Timbers Royalty Trust units are listed on the New York Stock Exchange under the symbol "CRT." From 1996 to 1998, the Company purchased 1,360,000, or 22.7%, of the outstanding units. The Board of Directors has authorized the purchase of up to two million, or 33%, of the outstanding units. In June 1998, the Company and Cross Timbers Royalty Trust filed a registration statement with the Securities and Exchange Commission to register the Company's 1,360,000 units for sale in a public offering. The registration statement was filed in anticipation of improving commodity prices and related market conditions for oil and gas equities. The registration statement was amended in October 2000. In December 1998, the Company formed the Hugoton Royalty Trust by conveying an 80% net profits interest in principally gas-producing operated interests in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. The Company sold 17 million units in the trust's initial public offering in 1999 and 1.3 million units pursuant to an employee incentive plan in 1999 and 2000. Hugoton Royalty Trust units are listed on the New York Stock Exchange under the symbol "HGT." Industry Operating Environment The oil and gas industry is affected by many factors that the Company generally cannot control. Governmental regulations, particularly in the areas of taxation, energy and the environment, can have a significant impact on operations and profitability. Crude oil prices are determined by global supply and demand. Oil supply is significantly influenced by production levels of OPEC member countries, while demand is largely driven by the condition of worldwide economies, as well as weather. The Company's natural gas prices are generally determined by North American supply and demand. Weather has a significant impact on demand for natural gas since it is a primary heating resource. Its increased use for electrical generation has kept natural gas demand elevated throughout the year, removing some of the seasonal swing in prices. See "General - Product Prices" in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations", regarding recent price fluctuations and their effect on the Company's results. Business Strategy The primary components of the Company's business strategy are: - acquiring long-lived, operated oil and gas properties, - increasing production and reserves through aggressive management of operations and through development, exploitation and exploration activities, and - retaining management and technical staff that have substantial experience in the Company's core areas. 2 Acquiring Long-Lived, Operated Properties. The Company seeks to acquire long-lived, operated producing properties that: - contain complex multiple-producing horizons with the potential for increases in reserves and production, - are in the Company's core operating areas or in areas with similar geologic and reservoir characteristics, and - present opportunities to reduce expenses per Mcfe produced through more efficient operations. The Company believes that the properties it acquires provide opportunities to increase production and reserves through the implementation of mechanical and operational improvements, workovers, behind-pipe completions, secondary recovery operations, new development wells and other development activities. The Company also seeks to acquire facilities related to gathering, processing, marketing and transporting oil and gas in areas where it owns reserves. Such facilities can enhance profitability, reduce gathering, processing, marketing and transportation costs, and provide marketing flexibility and access to additional markets. The Company's ability to successfully purchase properties is dependent upon, among other things, competition for such purchases and the availability of financing to supplement internally generated cash flow. Increasing Production and Reserves. A principal component of the Company's strategy is to increase production and reserves through aggressive management of operations and low-risk development. The Company believes that its principal properties possess geologic and reservoir characteristics that make them well suited for production increases through drilling and other development programs. The Company has generated an inventory of approximately 1,500 potential drilling locations for this program. Additionally, the Company reviews operations and mechanical data on operated properties to determine if actions can be taken to reduce operating costs or increase production. Such actions include installing, repairing and upgrading lifting equipment, redesigning downhole equipment to improve production from different zones, modifying gathering and other surface facilities and conducting restimulations and recompletions. The Company may also initiate, upgrade or revise existing secondary recovery operations. Exploration Activities. During 2001, the Company plans to focus on exploration projects that are near currently owned productive fields and have the potential to add substantially to proved reserves and cash flow. The Company believes that it can prudently and successfully add growth potential through exploratory activities given improved technology, its experienced technical staff and its expanded base of operations. The Company has allocated approximately $10 million of its $250 million 2001 development budget for exploration activities. Experienced Management and Technical Staff. Most senior management and technical staff have worked together for over 20 years and have substantial experience in the Company's core operating areas. Bob R. Simpson and Steffen E. Palko, co-founders of the Company, were previously executive officers of Southland Royalty Company, one of the largest U.S. independent oil and gas producers prior to its acquisition by Burlington Northern, Inc. in 1985. Other Strategies. The Company may also acquire working interests in producing properties that it will not operate if such interests otherwise meet its acquisition criteria. The Company attempts to acquire nonoperated interests in fields where the operators have a significant interest to protect. The Company may also acquire nonoperated interests in order to ultimately accumulate sufficient ownership interests to operate the properties. The Company attempts to acquire nonoperated interests with potential undeveloped reserves that will be exploited by the operator. The Company also attempts to acquire a portion of its reserves as royalty interests. Royalty interests have few operational liabilities because they do not participate in operating activities and do not bear production or development costs. Royalty Trusts. In December 1998, the Company created the Hugoton Royalty Trust and sold 42.5% of the trust to the public in April and May 1999. An additional 3.2% of the units were sold in 1999 and 2000, pursuant to an employee incentive plan. Sales of royalty trust units allow the Company to more efficiently capitalize its mature, lower growth properties. The Company may create and sell interests in additional royalty trusts in the future. 3 Business Goals. In November 2000, the Company announced its strategic goal for 2001of increasing gas production by 15%. This goal was updated in December to 20% gas production growth for 2001 and 2002. In March 2001, the Company announced goals for increasing proved reserves to 2.6 Tcfe at year-end 2001 and 3 Tcf equivalent at year-end 2002. To achieve these growth targets, the Company plans to drill about 245 (178 net) wells and perform approximately 380 (271 net) workovers and recompletions. The Company plans to reduce debt with operating cash flow. The Company has budgeted $250 million for its 2001 development program, which is expected to be funded primarily by cash flow from operations. About 50% of the development budget will be spent in East Texas with the balance evenly allocated to Arkoma Basin, San Juan Basin, Alaska, Permian Basin and Hugoton Royalty Trust properties. Exploration expenditures are expected to be approximately 4% of the 2001 budget. The total capital budget, including acquisitions, will be adjusted throughout 2001 depending on oil and gas prices to capitalize on opportunities offering the highest rates of return. Acquisitions During 1996, the Company acquired predominantly gas-producing properties for a total cost of $106 million. The Enserch Acquisition, the largest of these acquisitions, closed in July 1996 at a cost of $39.4 million and primarily consisted of operated interests in the Green River Basin of southwestern Wyoming. In November 1996, the Company acquired additional interests in the Fontenelle Unit, the most significant property included in the Enserch Acquisition, at a cost of $12.5 million. In December 1996, the Company acquired primarily operated interests in gas-producing properties in the Ozona area of the Permian Basin of West Texas for $28.1 million. The Company sold these properties for $43 million in March 2000. From July through December 1996, the Company acquired 955,800 units or 16% of the outstanding units of Cross Timbers Royalty Trust at a total cost of $12.8 million. The 1996 acquisitions increased proved reserves by approximately 1.6 million Bbls of oil and 153.4 Bcf of natural gas. During 1997, the Company acquired predominantly gas-producing properties for a total cost of $256 million. The Amoco Acquisition, the largest of these acquisitions, closed in December 1997 at an adjusted purchase price of $195 million, including five-year warrants to purchase 1.4 million shares of the Company's common stock at a price of $10.05 per share. This acquisition consisted primarily of operated properties in the San Juan Basin of New Mexico. In May 1997, the Company acquired properties in Oklahoma, Kansas and Texas for an adjusted purchase price of $39 million. The Company also acquired an additional 370,500 units, or 6%, of the Cross Timbers Royalty Trust units at a cost of $5.4 million. The 1997 acquisitions increased proved reserves by approximately 3.2 million Bbls of oil, 248 Bcf of natural gas and 13.9 million Bbls of natural gas liquids. During 1998, the Company acquired oil- and gas-producing properties for a total cost of $340 million. The East Texas Basin Acquisition was the largest of these acquisitions. The purchase closed in April 1998 at a price of $245 million which was reduced to $215 million by a $30 million production payment sold to EEX Corporation. In September 1998, the Company acquired oil-producing properties in the Middle Ground Shoal Field of Alaska's Cook Inlet in exchange for 2.9 million shares of the Company's common stock along with certain price guarantees and a non-interest bearing note payable of $6 million, resulting in a total purchase price of $45 million. The Company also acquired primarily gas- producing properties in northwest Oklahoma and the San Juan Basin of New Mexico for an estimated purchase price of $31 million. The 1998 acquisitions increased reserves by approximately 16.3 million Bbls of oil and 311.3 Bcf of natural gas. In 1999, the Company and Lehman Brothers Holdings, Inc. acquired the common stock of Spring Holding Company, a private oil and gas company, for a combination of cash and Cross Timbers' common stock totaling $85 million. The Company and Lehman each owned 50% of a limited liability company that acquired the common stock of Spring. In September 1999 the Company exercised its option to acquire Lehman's 50% interest in Spring for $44.3 million. This acquisition includes oil and gas properties located in the Arkoma Basin of Arkansas and Oklahoma with a purchase price of $235 million. After purchase accounting adjustments and other costs, the cost of the properties was $253 million. The Company also acquired, with Lehman as 50% owner, Arkoma Basin properties from affiliates of Ocean Energy, Inc. for $231 million. The Company exercised its option to acquire Lehman's interest in the Ocean Energy Acquisition on March 31, 2000 for $111 million. The 1999 acquisitions, including Lehman's 50% interest in the Spring and Ocean Energy acquisitions, increased reserves by approximately 2.8 million Bbls of oil and 494.7 Bcf of natural gas. 4 During 2000, the Company acquired oil- and gas-producing properties for a total cost of $32 million, including $11 million paid to Lehman in March 2000 in excess of its investment in the Ocean Energy Acquisition. There were no individually significant acquisitions in 2000. In December 2000, the Company entered into a definitive agreement with Herd Producing Company, Inc. to acquire primarily gas-producing properties in East Texas and Louisiana for $115 million. The purchase was completed on January 3, 2001, and increased reserves by approximately 175 Bcf of natural gas. Many of the properties acquired from 1996 through 1998 in Kansas, Oklahoma and Wyoming are subject to the 80% net profits interest conveyed to Hugoton Royalty Trust. The Company sold 45.7% of its Hugoton Royalty Trust units in 1999 and 2000. Significant Properties The following table summarizes proved reserves and discounted present value, before income tax, of proved reserves by the Company's major operating areas at December 31, 2000:
Proved Reserves --------------------------------------------------- Discounted (in thousands) Natural Gas Natural Gas Present Value Oil Gas Liquids Equivalents before Income Tax (Bbls) (Mcf) (Bbls) (Mcfe) of Proved Reserves ------- ---------- ----------- ----------- --------------------- East Texas....................... 2,870 621,645 - 638,865 $2,575,779 33.2% Arkoma Basin..................... 38 478,776 - 479,004 2,028,993 26.2% San Juan Basin................... 1,447 291,829 22,012 432,583 1,249,886 16.1% Hugoton Royalty Trust (a)........ 2,877 326,582 - 343,844 1,230,419 15.9% Permian Basin.................... 35,285 34,909 - 246,619 451,071 5.8% Alaska Cook Inlet................ 13,873 - - 83,238 128,412 1.7% Cross Timbers Royalty Trust (b).. 1,710 12,410 - 22,670 63,185 0.8% Other............................ 345 3,532 - 5,602 20,887 0.3% ------- ---------- ----------- ----------- ---------- ------ Total............................ 58,445 1,769,683 22,012 2,252,425 $7,748,632 100.0% ======= ========== =========== =========== ========== ======
(a) Includes 1,970,000 Bbls of oil and 223,578,000 Mcf of gas and discounted present value before income tax of $842,346,000 related to the Company's ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2000. (b) Includes 747,000 Bbls of oil and 7,986,000 Mcf of gas and discounted present value before income tax of $38,403,000 related to the Company's ownership of approximately 23% of Cross Timbers Royalty Trust units at December 31, 2000. East Texas Area The Company acquired most of its producing properties in the East Texas area in April 1998. These properties are located in East Texas and northwestern Louisiana and produce primarily from the Travis Peak, Cotton Valley and Rodessa formations between 7,000 feet and 12,000 feet in eight major fields. Oil and gas were first discovered in the East Texas area in the 1930's. The Company owns an interest in 652 gross (635 net) wells which it operates and 46 gross (5.8 net) wells operated by others. The Company also owns the related gathering facilities. During 2000, the East Texas area was the Company's most active gas development area, where 44 gross (42.3 net) gas wells were drilled and 97 workovers were performed. The formations targeted were the Travis Peak, Cotton Valley and Bossier. The Company plans to continue to extensively develop this area, including drilling approximately 97 wells in 2001. Arkoma Basin Area During 1999, the Company acquired interests in approximately 2,500 wells and a gas gathering system in the Arkoma Basin of Arkansas and Oklahoma. The Arkoma Basin, discovered in the 1920's, stretches from central Arkansas into eastern Oklahoma and is known for shallow production decline rates, multiple formations and complex geology. With these acquisitions, the Company controls 40% of Arkansas production from the Arkoma Basin. The Company owns an interest in 839 gross (589.8 net) wells which it operates and 626 gross (112.8 net) wells operated by 5 others. Of these wells, 136 gross (87.7 net) operated wells and 72 gross (13.7 net) nonoperated wells are dual completions. The acquired properties can be separated into three distinct areas, which are the Oklahoma Cromwell/Atoka trend, the Arkansas Fairway trend and the Arkansas Overthrust trend. The Oklahoma Cromwell/Atoka trend of eastern Oklahoma was originally developed in the 1970's targeting the Cromwell Sands and Atoka formations. The Arkansas Fairway trend is comprised of multiple sandstones at depths ranging from 2,500 to 7,500 feet in the Atoka and Morrow intervals. The Arkansas Overthrust trend is characterized by extremely complex geology and will require an ongoing process to develop the best exploitation opportunities. In 2000, the Company drilled 47 gross (27.5 net) wells, completed 90 workovers, including 20 wellhead compressors, and drilled two successful exploration wells in the Pine Hollow Field. The Company plans to drill 70 wells, perform 115 workovers and install 80 wellhead compressors in the Arkoma Basin during 2001. San Juan Basin Area The San Juan Basin of northwestern New Mexico and southwestern Colorado contains the second largest natural gas reserves in North America. The Company acquired most of its interests in the San Juan Basin in December 1997 from a subsidiary of Amoco Corporation. The Company owns an interest in 684 gross (550.2 net) wells that it operates and 372 gross (90.7 net) wells operated by others. Of these wells, 82 gross (71.2 net) operated wells and six gross (0.6 net) nonoperated wells are dual completions. During 2000, the Company participated in the drilling of 34 gross (27.1 net) wells, completed 19 workovers and installed over 93 wellhead compressors. During 2001, the Company plans to drill 43 wells and perform 15 workovers. The Company also plans to continue to install wellhead compressors at approximately the same level as 2000. Hugoton Royalty Trust Areas A substantial portion of properties in the Mid-Continent area, the Hugoton area and the Green River Basin of the Rocky Mountains are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust as of December 1998. The Company sold 45.7% of its Hugoton Royalty Trust units in 1999 and 2000. Mid-Continent Area The Company is one of the largest producers in the Major County, Oklahoma area of the Anadarko Basin. The Company operates 459 gross (402.5 net) wells and has an interest in 113 gross (30.3 net) wells operated by others. Oil and gas were first discovered in the Major County area in 1945. The fields in the Major County area are located in the Anadarko Basin and are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations. The Company develops the Major County area primarily through mechanical improvements, restimulations, recompletions to shallower zones and development drilling. During 2000, the Company participated in the drilling of 18 gross (12.9 net) wells in the northwestern portion of the County, targeting the Chester, Inola, Oswego and Red Fork formations. The Company has budgeted 10 drill wells in Major County for 2001. The Company operates a gathering system and pipeline in the Major County area. The gathering system collects gas from over 400 wells through 300 miles of pipeline in the Major County area. The gathering system has current throughput of approximately 18,000 Mcf per day, 70% of which is produced from Company-operated wells. Estimated capacity of the gathering system is 40,000 Mcf per day. Gas is delivered to a processing plant owned and operated by a third party, and then transmitted by a 26-mile Company-operated pipeline to connections with other pipelines. 6 The Company was also very active in Woodward County, Oklahoma, where 15 gross (13.7 net) wells were drilled. In 2001, the Company plans to drill up to 15 wells. Hugoton Area The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and Kansas and is the largest gas field in North America with an estimated five million productive acres. The Company owns an interest in 380 gross (356.5 net) wells that it operates and 77 gross (18.2 net) wells operated by others. Approximately 70% of the Company's Hugoton gas production is delivered to the Tyrone Plant, a gas processing plant operated by the Company. During 1998, the Company completed the acquisition of approximately 70 miles of low pressure gathering lines, increasing production by 3,500 Mcf per day. During 1999 and 2000, the Company installed additional lateral compressors that lowered the line pressure and increased production in various areas of the Hugoton Field. While much of the Kansas portion of the Hugoton Field has been infill drilled on 320-acre spacing, the Company believes that there are up to 35 additional potential infill drilling locations. In June 1999, Oklahoma regulations were amended to allow increased drilling density in the Oklahoma portion which was previously drilled on 640-acre spacing. The Company believes it has approximately 200 potential infill drilling locations in Oklahoma. During 2000, the Company drilled one well to the Chester, Council Grove and Oswego formations. Green River Basin The Green River Basin is located in southwestern Wyoming. The Company has interests in 179 gross (177.5 net) wells that it operates and 31 gross (4.1 net) wells operated by others in the Fontenelle Field. Gas production began in the Fontenelle area in the early 1970's. The producing reservoirs are the Cretaceous Frontier and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. Development potential for the fields in this area include deepening and opening new producing zones in existing wells, drilling new wells and adding compression to lower line pressures. During 2000, the Company drilled five gross (4.9 net) wells in the Fontenelle Unit and plans to drill 10 wells during 2001. Permian Basin Area Prentice Field. The Prentice Field is located in Terry and Yoakum Counties, Texas. Discovered in 1950, the Prentice Field produces from carbonate reservoirs in the Clear Fork and Glorieta formations at depths ranging from 6,000 to 7,000 feet. The Prentice Field has been separated into several waterflood units for secondary recovery operations. The Prentice Northeast Unit was formed in 1964 with waterflood operations commencing a year later. Development potential exists through infill drilling and improvement of waterflood efficiency. Tertiary recovery potential also exists through carbon dioxide flooding. The Company has a 91.5% working interest in 178 wells in the Prentice Northeast Unit. The Company also owns an interest in 81 gross (2 net) nonoperated wells. During 2000, the Company drilled 11 gross (10.1 net) vertical wells. At the end of 2000, one well was still being completed. During 2001, the Company may drill as many as 15 wells in this field. University Block 9. The University Block 9 Field is located in Andrews County, Texas and was discovered in 1953. The Company owns interests in 70 gross (68.5 net) wells that it operates. Productive zones are of Wolfcamp, Pennsylvanian and Devonian age and range from 8,400 to 10,400 feet. Development potential includes proper wellbore utilization, recompletions, infill drilling and improvement of waterflood efficiency. 7 This field was the Company's most active oil development area during 2000, where the Company drilled 26 wells, including seven horizontal sidetrack wells. The Company also recompleted five Devonian wells into the Pennsylvanian horizon. During 2001, the Company plans to drill up to 19 wells. Alaska Cook Inlet Area In September 1998, the Company acquired a 100% working interest in two State of Alaska leases and the offshore installations located in the Middle Ground Shoal Field of the Cook Inlet. The properties include 27 wells, two operated production platforms set in 70 feet of water about seven miles offshore, and a 50% interest in certain operated production pipelines and onshore processing facilities. Oil was discovered in the Cook Inlet in 1966. Production from the 29 operated wells is primarily from multiple zones within the Miocene-Oligocene- aged Tyonek formation between 7,300 feet and 10,000 feet subsea. Three workovers were performed and two wells were drilled in 2000. The Company plans to drill two wells in 2001. Reserves The following are definitions adopted by the Commission and the Financial Accounting Standards Board which are applicable to terms used in the following discussion of oil and natural gas reserves: Proved reserves- Estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. Proved developed reserves- Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves- Proved reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Estimated future net revenues- Also referred to herein as "estimated future net cash flows." Computational result of applying current prices of oil and gas (with consideration of price changes only to the extent provided by existing contractual arrangements) to estimated future production from proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves. Present value of estimated future net cash flows- Also referred to herein as "standardized measure of discounted future net cash flows" or "standardized measure." Computational result of discounting estimated future net revenues at a rate of 10% annually. 8 The following are estimated quantities of proved reserves and cash flows therefrom as of December 31, 2000, 1999 and 1998: December 31 ----------------------------------- (in thousands) 2000 1999 1998 ----------- ---------- ---------- Proved developed: Oil (Bbls)......................... 46,334 48,010 42,876 Gas (Mcf).......................... 1,328,953 1,225,014 968,495 Natural gas liquids (Bbls)......... 16,448 13,781 14,000 Mcfe............................... 1,705,645 1,595,760 1,309,751 Proved undeveloped: Oil (Bbls)......................... 12,111 13,593 11,634 Gas (Mcf).......................... 440,730 320,609 240,729 Natural gas liquids (Bbls)......... 5,564 4,121 3,174 Mcfe............................... 546,780 426,893 329,577 Total proved: Oil (Bbls)......................... 58,445 61,603 54,510 Gas (Mcf).......................... 1,769,683 1,545,623 1,209,224 Natural gas liquids (Bbls)......... 22,012 17,902 17,174 Mcfe............................... 2,252,425 2,022,653 1,639,328 Estimated future net cash flows: Before income tax.................. $15,239,560 $3,269,443 $1,677,426 After income tax................... $10,291,946 $2,550,551 $1,446,177 Present value of estimated future net cash flows, discounted at 10%: Before income tax.................. $ 7,748,632 $1,765,936 $ 908,606 After income tax................... $ 5,262,030 $1,396,940 $ 808,403 Miller and Lents, Ltd., an independent petroleum engineering firm, prepared the estimates of the Company's proved reserves and the future net cash flow (and present value thereof) attributable to proved reserves at December 31, 2000, 1999 and 1998. As prescribed by the Commission, such proved reserves were estimated using oil and gas prices and production and development costs as of December 31 of each such year, without escalation. Year-end 2000 realized prices used in the estimation of proved reserves were $25.49 per Bbl for oil, $9.55 per Mcf for gas and $26.33 per Bbl for natural gas liquids. Based on NYMEX prices of $25.00 per Bbl for oil and $5.00 per Mcf for gas (which are comparable to realized prices of $23.69 per Bbl for oil and $4.79 per Mcf for gas), and an $18.86 per Bbl realized price for natural gas liquids, estimated proved reserves at December 31, 2000 would be 57.7 million Bbls of oil, 1.75 Tcf of natural gas and 21.6 million Bbls of natural gas liquids. Using these prices, the present value of estimated future cash flows, discounted at 10% and before income tax, would be $3,834,024,000. See Note 16 to Consolidated Financial Statements for additional information regarding estimated proved reserves. Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond the Company's control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as change in product prices, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates. During 2000, the Company filed estimates of oil and gas reserves as of December 31, 1999 with the U.S. Department of Energy on Form EIA-23. These estimates are consistent with the reserve data reported for the year ended December 31, 1999 in Note 16 to Consolidated Financial Statements, with the exception that Form EIA-23 includes only reserves from properties operated by the Company. 9 Exploration and Production Data For the following data, "gross" refers to the total wells or acres in which the Company owns a working interest and "net" refers to gross wells or acres multiplied by the percentage working interest owned by the Company. Although many of the Company's wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio of oil to gas production. Producing Wells The following table summarizes the Company's producing wells as of December 31, 2000, all of which are located in the United States: Operated Wells Nonoperated Wells Total (a) ------------------ ----------------- ------------------ Gross Net Gross Net Gross Net ----- ----------- ----- ----- ----- ----------- Oil............ 542 484.7 1,806 126.4 2,348 611.1 Gas............ 3,227 2,728.7 1,310 269.2 4,537 2,997.9 ----- ----------- ----- ----- ----- ----------- Total.......... 3,769 3,213.4 3,116 395.6 6,885 3,609.0 ===== =========== ===== ===== ===== =========== (a) One gross (0.5 net) oil wells and 317 gross (194.7 net) gas wells are dual completions. Drilling Activity The following table summarizes the number of development wells drilled by the Company during the years indicated. As of December 31, 2000, the Company was in the process of drilling 59 gross (41.9 net) wells. Year Ended December 31 --------------------------------------------------- 2000 1999 1998 ---------------- ---------------- --------------- Gross Net Gross Net Gross Net ------- ------- ------- ------- ------- ------- Development wells: Completed as- Oil wells.............. 48 29.9 18 6.7 53 14.1 Gas wells.............. 172 114.6 128 91.2 139 63.4 Non-productive........... 9 1.3 7 3.5 1 - ------- ------- ------- ------- ------- ------- Total.................... 229 145.8 153 101.4 193 77.5 ------- ------- ------- ------- ------- ------- Exploratory wells: Completed as- Oil wells.............. 4 2.8 - - - - Gas wells.............. 1 0.5 1 1.0 3 3.0 Non-productive........... 1 0.5 - - 2 1.0 ------- ------- ------- ------- ------- ------- Total.................... 6 3.8 1 1.0 5 4.0 ------- ------- ------- ------- ------- ------- Total (a)................. 235 149.6 154 102.4 198 81.5 ======= ======= ======= ======= ======= ======= (a) Included in totals are 66 gross (8.5 net) wells in 2000, 44 gross (4.1 net) wells in 1999 and 118 gross (14.6 net) in 1998 drilled on nonoperated interests. 10 Acreage The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest as of December 31, 2000. Excluded from this summary is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests. Developed Acres (a)(b) Undeveloped Acres ---------------------- ----------------- Gross Net Gross Net --------- ------- ------ ------ Arkansas.... 519,646 226,345 20,495 15,678 Oklahoma.... 464,737 324,766 14,783 6,783 Texas....... 223,398 140,500 27,190 20,492 New Mexico.. 196,078 145,963 160 160 Kansas...... 66,670 58,169 - - Wyoming..... 45,007 30,241 1,891 1,211 Other....... 35,157 19,602 4,603 4,002 --------- ------- ------ ------ Total....... 1,550,693 945,586 69,122 48,326 ========= ======= ====== ====== (a) Developed acres are acres spaced or assignable to productive wells. (b) Certain acreage in Oklahoma and Texas is subject to a 75% net profits interest conveyed to the Cross Timbers Royalty Trust, and in Oklahoma, Kansas and Wyoming is subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust. Oil and Gas Sales Prices and Production Costs The following table shows the average sales prices per Bbl of oil (including condensate), Mcf of gas and per Bbl of natural gas liquids produced and the production costs and taxes, transportation and other per thousand cubic feet of gas equivalent ("Mcfe," computed on an energy equivalent basis of six Mcf to one Bbl): Year Ended December 31 ---------------------- 2000 1999 1998 ------ ------ ------ Sales prices: Oil (per Bbl)............................ $27.07 $16.94 $12.21 Gas (per Mcf)............................ $ 3.38 $ 2.13 $ 2.07 Natural gas liquids (per Bbl)............ $19.61 $11.80 $ 7.62 Production costs per Mcfe................. $ 0.53 $ 0.53 $ 0.53 Taxes, transportation and other per Mcfe.. $ 0.35 $ 0.23 $ 0.25 Delivery Commitments The Company contracted to sell to a single purchaser approximately 21,650 Mcf of gas per day at the index price through December 2000, 34,344 Mcf per day at the index price in 2001 and 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Deliveries under this contract are in Oklahoma and Arkansas. The Company has committed to sell all gas production from certain East Texas properties to EEX Corporation at market prices through the earlier of December 31, 2001, or until a total of approximately 34.3 Bcf (27.8 Bcf net to the Company's interest) of gas has been delivered. Based on current production, this sales commitment is approximately 24,700 Mcf (20,000 Mcf net to the Company's interest) per day. As partial consideration for an acquisition, the Company agreed to sell gas volumes ranging from 40,000 Mcf in 2000 to 35,000 Mcf in 2003 at specified discounts from index prices. Delivery of 20,000 Mcf per day of committed sales volumes is in the San Juan Basin, and delivery of the remaining volumes is in the East Texas Basin. 11 As a part of the Ocean Energy Acquisition, the Company assumed a commitment to sell 6,800 Mcf of gas per day through April 2003 at a prices which are adjusted by the monthly index price. In 2000, the prices ranged from $0.50 to $0.95 per Mcf. Delivery of the committed sales volumes is in Arkansas. The Company has also entered fixed price contracts to sell physical daily gas volumes of 210,000 Mcf from April through September 2001 and 140,000 Mcf from October through March 2002. See Note 8 to Consolidated Financial Statements. The Company's production and reserves are adequate to meet the above sales commitments. Competition and Markets The Company faces competition from other oil and gas companies in all aspects of its business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Many of its competitors have substantially larger financial and other resources. Factors that affect the Company's ability to acquire producing properties include available funds, available information about the property and the Company's standards established for minimum projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Because of the long-lived, high margin nature of the Company's oil and gas reserves and management's experience and expertise in exploiting these reserves, management believes that it is effective in competing in the market. The Company's ability to market oil and gas depends on many factors beyond its control, including the extent of domestic production and imports of oil and gas, the proximity of the Company's gas production to pipelines, the available capacity in such pipelines, the demand for oil and gas, the effects of weather, and the effects of state and federal regulation. The Company cannot assure that it will always be able to market all of its production or obtain favorable prices. The Company, however, does not currently believe that the loss of any of its oil or gas purchasers would have a material adverse effect on its operations. Decreases in oil and gas prices have had and could have in the future an adverse effect on the Company's acquisition and development programs, proved reserves, revenues, profitability, cash flow and dividends. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, "General - Product Prices." Federal and State Regulations There have been, and continue to be, numerous federal and state laws and regulations governing the oil and gas industry that are often changed in response to the current political or economic environment. Compliance with this regulatory burden is often difficult and costly and may carry substantial penalties for noncompliance. The following are some specific regulations that may affect the Company. The Company cannot predict the impact of these or future legislative or regulatory initiatives. Federal Regulation of Natural Gas The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates charged and various other matters, by the Federal Energy Regulatory Commission ("FERC"). Federal wellhead price controls on all domestic gas were terminated on January 1, 1993 and none of the Company's gathering systems are currently subject to FERC regulation. The Company cannot predict the impact of future government regulation on any natural gas facilities. Although FERC's regulations should generally facilitate the transportation of gas produced from the Company's properties and the direct access to end-user markets, the future impact of these regulations on marketing the Company's production or on its gas transportation business cannot be predicted. The Company, however, does not believe that it will be affected differently than competing producers and marketers. 12 Federal Regulation of Oil Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. A significant part of the Company's oil production is transported by pipeline. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. The United States Court of Appeals upheld FERC's orders in 1996. These rules have had little effect on the Company's oil transportation cost. State Regulation Oil and gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the method of developing new fields, the spacing and operations of wells and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and gas wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled. The Company may become a party to agreements relating to the construction or operations of pipeline systems for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the state's administrative authority charged with regulating pipelines. The rates that can be charged for gas, the transportation of gas, and the construction and operation of such pipelines would be subject to the regulations governing such matters. Certain states have recently adopted regulations with respect to gathering systems, and other states are considering similar regulations. New regulations have not had a material effect on the operations of the Company's gathering systems, but the Company cannot predict whether any further rules will be adopted or, if adopted, the effect these rules may have on its gathering systems. Federal, State or Native American Leases The Company's operations on federal, state or Native American oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service and other agencies. Environmental Regulations Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact the Company's operations and costs. Management believes that the Company is in substantial compliance with applicable environmental laws and regulations. To date, the Company has not expended any material amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on the consolidated financial position or results of operations of the Company. 13 Employees The Company had 651 employees as of December 31, 2000. None of the employees are represented by a union. The Company considers its relations with its employees to be good. Executive Officers of the Company The executive officers of the Company are elected by and serve until their successors are elected by the Board of Directors. Bob R. Simpson, 52, was a co-founder of the Company with Mr. Palko and has been Chairman and Chief Executive Officer of the Company since July 1, 1996. Prior thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer or held similar positions with the Company since 1986. Mr. Simpson was Vice President of Finance and Corporate Development (1979-1986) and Tax Manager (1976-1979) of Southland Royalty Company. Steffen E. Palko, 50, was a co-founder of the Company with Mr. Simpson and has been Vice Chairman and President or held similar positions with the Company since 1986. Mr. Palko was Vice President - Reservoir Engineering (1984-1986) and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company. Louis G. Baldwin, 51, has been Executive Vice President and Chief Financial Officer or held similar positions with the Company since 1986. Mr. Baldwin was Assistant Treasurer (1979-1986) and Financial Analyst (1976-1979) at Southland Royalty Company. Keith A. Hutton, 42, has been Executive Vice President - Operations or held similar positions with the Company since 1987. From 1982 to 1987, Mr. Hutton was a Reservoir Engineer with Sun Exploration & Production Company. Vaughn O. Vennerberg, II, 46, has been Executive Vice President - Administration or held similar positions with the Company since 1987. Prior to that time, Mr. Vennerberg was Land Manager with Hutton Gas Operating Company (1986-1987). Bennie G. Kniffen, 50, has been Senior Vice President and Controller or held similar positions with the Company since 1986. From 1976 to 1986, Mr. Kniffen held the position of Director of Auditing or similar positions with Southland Royalty Company. 14 Item 3. Legal Proceedings On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against the Company in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which the Company has assumed the obligation to pay royalties. The plaintiffs allege that the Company has reduced royalty payments by post-production deductions and has entered into contracts with subsidiaries that were not arm's-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by the Company in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. The Company contends that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm's-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. The Company further contends that any such fees enhance the value of the gas or the products derived from the gas. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. A hearing on the class certification issue has not been scheduled. Management believes it has strong defenses against this claim and intends to vigorously defend the action. Management's estimate of the potential liability from this claim has been accrued in the Company's financial statements. On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against the Company and certain of its subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that the Company underpaid royalties on gas produced from federal leases and lands owned by Native Americans by at least 20% during the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for the Company to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against the Company and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. The Company and other defendants filed a motion to dismiss which has been heard by the Court and a decision is pending. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim is not currently determinable and no provision has been accrued in the Company's financial statements. A third lawsuit, Bishop, et al. v. Amoco Production Co., et al., was filed in May 2000 in the Third Judicial District Court in Lincoln County, Wyoming by owners of royalty and overriding royalty interests in wells located in Wyoming. The plaintiffs alleged that the Company and the other producer defendants deducted impermissible costs of production from royalty payments that were made to the plaintiffs and other similarly situated persons and failed to properly inform the plaintiffs and others of the deductions taken as allegedly required by Wyoming statutes. The action was brought as a class action on behalf of all persons who own an interest in wells located in Wyoming as to which the defendants pay royalties and overriding royalties. The plaintiffs sought a declaratory judgment that the deductions made were impermissible and sought damages in the amount of the deductions made, together with interest and attorneys' fees. The Company has reached a settlement of this action, which is subject to court approval. The Company has agreed to pay a total settlement amount of $572,000 for a release of claims relating to deductions taken by the Company, the statutory reporting of claims, and other miscellaneous matters. The Company further agreed that it would not take similar deductions from royalty owners in the future and to itemize other deductions from future royalty disbursements. The Company expects that the court will approve the settlement in April 2001. The settlement was accrued in the Company's financial statements. In February 2000, the Department of Interior notified the Company and several other producers that certain Native American leases located in the San Juan Basin have expired due to the failure of the leases to produce in paying quantities. The Department of Interior has demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. The Company has filed a Notice of Appeal with the Interior Board of Indian Appeals. The potential loss from these claims is currently not determinable, but could be material to the Company's annual earnings. The Company believes that the 15 claim is without merit and that there is currently not a probable loss. No related provision is accrued in the Company's financial statements. The Company is involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on the Company's financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year. Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted for a vote of security holders during the fourth quarter of 2000. 16 PART II ------- Item 5. Market for Registrant's Common Equity and Related Stockholder Matters The Company's common stock is listed on the New York Stock Exchange and trades under the symbol "XTO." The following table sets forth quarterly high and low sales prices and cash dividends declared for each quarter of 2000 and 1999 (as adjusted for the three-for-two stock split effected on September 18, 2000):
High Low Dividend ------ ------- ---------- 2000 First Quarter.......... $ 8.917 $ 5.042 $ 0.0067 Second Quarter......... 14.833 8.167 0.0067 Third Quarter.......... 21.625 10.667 0.0100 Fourth Quarter......... 29.000 16.750 0.0100 1999 First Quarter.......... $ 6.042 $ 3.042 $ 0.0067 Second Quarter......... 9.917 4.500 0.0067 Third Quarter.......... 10.083 7.333 0.0067 Fourth Quarter......... 8.875 5.458 0.0067
The determination of the amount of future dividends, if any, to be declared and paid is in the sole discretion of the Company's Board of Directors and will depend on the Company's financial condition, earnings and funds from operations, the level of its capital expenditures, dividend restrictions in its financing agreements, its future business prospects and other matters as the Board of Directors deems relevant. Furthermore, the Company's revolving credit agreement with banks restricts the amount of dividends to 25% of cash flow from operations, as defined, for the latest four consecutive quarterly periods. The Company's 9 1/4% and 8 3/4% senior subordinated notes also place certain restrictions on distributions to common shareholders, including dividend payments. On February 20, 2001, the Board of Directors declared a quarterly dividend of $.01 per share payable on April 17, 2001 to shareholders of record on March 30, 2001. On March 1, 2001, the Company had approximately 593 shareholders of record. 17 Item 6. Selected Financial Data The following table shows selected financial information for the five years ended December 31, 2000. Significant producing property acquisitions in each of the years presented affect the comparability of year-to-year financial and operating data. All weighted average shares and per share data have been adjusted for the three-for-two stock splits effected in March 1997, February 1998 and September 2000. This information should be read in conjunction with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements at Item 14(a).
(in thousands except production, per share and per unit data) 2000 1999 1998 1997 1996 ---------- ---------- ----------- ---------- --------- Consolidated Income Statement Data Revenues: Oil and condensate.......................... $ 128,194 $ 86,604 $ 56,164 $ 75,223 $ 75,013 Gas and natural gas liquids................. 456,814 239,056 182,587 110,104 73,402 Gas gathering, processing and marketing..... 16,123 10,644 9,438 9,851 12,032 Other....................................... (280) 4,991 1,297 3,094 888 ---------- ---------- ----------- ---------- --------- Total Revenues.............................. $ 600,851 $ 341,295 $ 249,486 $ 198,272 $ 161,335 ========== ========== =========== ========== ========= Earnings (loss) available to common stock.... $ 115,235(a) $44,964(b)$ (71,498)(c) $ 23,905 $ 19,790 ========== ========== =========== ========== ========= Per common share Basic....................................... $ 1.62 $ 0.64 $ (1.10) $ 0.40 $ 0.33 ========== ========== =========== ========== ========= Diluted..................................... $ 1.55 $ 0.63 $ (1.10) $ 0.39 $ 0.32 ========== ========== =========== ========== ========= Weighted average common shares outstanding.. 71,154 70,228 65,094 59,660 59,870 ========== ========== =========== ========== ========= Dividends declared per common share.......... $ 0.0333 $ 0.0267 $ 0.1067 $ 0.1000 $ 0.0867 ========== ========== =========== ========== ========= Consolidated Statement of Cash Flows Data Cash provided (used) by: Operating activities........................ $ 377,421 $ 133,301 $ (53,876) $ 95,918 $ 59,694 Investing activities........................ $ (133,884) $ (156,370) $ (376,564) $ (309,234) $(124,871) Financing activities........................ $ (241,833) $ 16,470 $ 438,957 $ 213,195 $ 66,902 Consolidated Balance Sheet Data Property and equipment, net.................. $1,357,374 $1,339,080 $ 1,050,422 $ 723,836 $ 450,561 Total assets................................. $1,591,904 $1,477,081 $ 1,207,005 $ 788,455 $ 523,070 Long-term debt............................... $ 769,000 $ 991,100 $ 920,411 $ 539,000 $ 314,757 Stockholders' equity......................... $ 497,367 $ 277,817 $ 201,474 $ 170,243 $ 142,668 Operating Data Average daily production: Oil (Bbls).................................. 12,941 14,006 12,598 10,905 9,584 Gas (Mcf)................................... 343,871 288,000 229,717 135,855 101,845 Natural gas liquids (Bbls).................. 4,430 3,631 3,347 220 - Mcfe........................................ 448,098 393,826 325,390 202,609 159,349 Average sales price: Oil (per Bbl)............................... $ 27.07 $ 16.94 $ 12.21 $ 18.90 $ 21.38 Gas (per Mcf)............................... $ 3.38 $ 2.13 $ 2.07 $ 2.20 $ 1.97 Natural gas liquids (per Bbl)............... $ 19.61 $ 11.80 $ 7.62 $ 9.66 - Production expense (per Mcfe)................ $ 0.53 $ 0.53 $ 0.53 $ 0.59 $ 0.67 Taxes, transportation and other (per Mcfe)... $ 0.35 $ 0.23 $ 0.25 $ 0.22 $ 0.20 Proved reserves: Oil (Bbls).................................. 58,445 61,603 54,510 47,854 42,440 Gas (Mcf)................................... 1,769,683 1,545,623 1,209,224 815,775 540,538 Natural gas liquids (Bbls).................. 22,012 17,902 17,174 13,810 - Mcfe........................................ 2,252,425 2,022,653 1,639,328 1,185,759 795,178 Other Data Operating cash flow (d)...................... $ 344,638 $ 132,683 $ 78,480 $ 89,979 $ 68,263 Ratio of earnings to fixed charges (e)....... 2.8 1.9 - (f) 2.1 2.6
18 (a) Includes effect of pre-tax gain of $43.2 million on significant asset sales, pre-tax derivative fair value loss of $55.8 million and non-cash incentive compensation expense of $26.1 million. (b) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton Royalty Trust units. (c) Includes effect of a $93.7 million pre-tax net loss on investment in equity securities and a $2 million pre-tax, non-cash impairment charge. (d) Defined as cash provided by operating activities before changes in operating assets and liabilities and exploration expense. Because of exclusion of changes in operating assets and liabilities and exploration expense, this cash flow statistic is different from cash provided (used) by operating activities, as is disclosed under generally accepted accounting principles. (e) For purposes of calculating this ratio, earnings include earnings (loss) available to common stock before income tax and fixed charges. Fixed charges include interest costs, the portion of rentals (calculated as one- third) considered to be representative of the interest factor and preferred stock dividends. (f) Fixed charges exceeded earnings by $108.4 million. Excluding the effect of items in (c) above, fixed charges exceeded earnings by $19 million. 19 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis should be read in conjunction with Item 6, "Selected Financial Data" and the Company's consolidated financial statements at Item 14(a). General The following events affect the comparability of results of operations and financial condition for the years ended December 31, 2000, 1999 and 1998, and may impact future operations and financial condition. Throughout this discussion, the term "Mcfe" refers to thousands of cubic feet of gas equivalent quantities produced for the indicated period, with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf. Three-for-Two Stock Splits. The Company effected three-for-two stock splits on February 25, 1998 and September 18, 2000. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect all stock splits. 1999 Acquisitions. During 1999, the Company acquired predominantly gas-producing properties at a total cost of $510 million primarily funded by a combination of bank borrowings, proceeds from a public offering of common stock and the issuance of common stock. The acquisitions include: - Spring Holding Company Acquisition. In July 1999, the Company and Lehman each acquired 50% of the common stock of Spring Holding Company for a combination of cash and the Company's common stock totaling $85 million. In September 1999, the Company exercised its option to acquire Lehman's 50% interest in Spring for $44.3 million. The acquisition includes gas properties located in the Arkoma Basin of Arkansas and Oklahoma with a purchase price of $235 million. After purchase accounting adjustments and other costs, the cost of the properties was $257 million. - Ocean Energy Acquisition. In September 1999, the Company and Lehman acquired Arkoma Basin gas properties for $231 million. Lehman contributed $100 million in cash and the Company contributed $100 million in securities, including its common stock, to a jointly owned company. The acquisition was funded with cash of $100 million and bank borrowings of $131 million. The Company acquired Lehman's interest in this acquisition on March 31, 2000 for $111 million, which was funded by proceeds from the sales of producing properties and equity securities, as well as bank debt. The $11 million in excess of Lehman's investment was recorded as additional property cost in 2000. 1998 Acquisitions. During 1998, the Company acquired oil- and gas-producing properties at a total cost of $340 million, including: - East Texas Basin Acquisition. The Company acquired these primarily gas- producing properties at a purchase price of $245 million, later reduced to $215 million by a $30 million production payment sold to EEX Corporation. This acquisition closed in April 1998 and was funded by bank debt, partially repaid from proceeds of the 1998 Common Stock Offering. - Cook Inlet Acquisition. In September 1998, the Company acquired these oil- producing properties in Alaska from affiliates of Shell Oil Company in exchange for 2.9 million shares of the Company's common stock along with certain price guarantees and a non-interest bearing note payable of $6 million, resulting in a purchase price of $45 million. - Seagull Acquisition. This acquisition included primarily gas-producing properties in northwest Oklahoma and the San Juan Basin of New Mexico. The Company acquired these properties in November 1998 for an estimated purchase price of $31 million, funded by bank borrowings. Hugoton Royalty Trust Sales. The Company created Hugoton Royalty Trust in December 1998 by conveying 80% net profits interests in producing properties in Kansas, Oklahoma and Wyoming. In April and May 1999, the Company sold 17 million units, or 42.5%, of Hugoton Royalty Trust in its initial public offering. Total proceeds from this sale were $148.6 million, which were used to reduce bank debt. Total gain on sale, including the sale of units pursuant to an 20 employee incentive plan, was $40.6 million before income tax. In October and November 2000, the Company sold 1.2 million units, or approximately 3%, of Hugoton Royalty Trust pursuant to the employee incentive plan. Total gain on these sales during 2000 was $11 million before income tax. 2000 Property Sales. In March 2000, the Company sold oil- and gas-producing properties in Crockett County, Texas and Lea County, New Mexico for total gross proceeds of $68.3 million. 1999 Property Sales. In May and June 1999, the Company sold primarily nonoperated gas-producing properties in New Mexico for $44.9 million. In September 1999, the Company sold primarily nonoperated oil- and gas-producing properties in Oklahoma, Texas, New Mexico and Wyoming for $63.5 million, including sales of $22.5 million of properties acquired in the Spring Holding Company Acquisition. 2000, 1999 and 1998 Development and Exploration Programs. Oil development was concentrated in the University Block 9 Field during all three years. Gas development focused on the East Texas area in 2000 and 1999, the Hugoton Area during 1998, and the Fontenelle Unit during all three years. Exploration activity has been primarily geological and geophysical analysis, including seismic studies, of undeveloped properties. Exploratory expenditures were $1 million in 2000, $900,000 in 1999 and $8 million in 1998. 2001 Development and Exploration Program. The Company has budgeted $250 million for its 2001 development and exploration program, which is expected to be funded primarily by cash flow from operations. The Company anticipates exploration expenditures will be approximately 4% of the 2001 budget. The total capital budget, including acquisitions, will be adjusted throughout 2001 to focus on opportunities offering the highest rates of return. Common Stock Transactions. The following significant sales and issuances of common stock occurred during the three-year period ended December 31, 2000: - In November 2000, the Company sold 6.6 million shares of common stock from treasury with net proceeds of approximately $126.1 million. The proceeds were used to reduce outstanding indebtedness. - In July 1999, the Company sold 3 million shares of common stock from treasury with net proceeds of approximately $26.5 million. The proceeds were used to repurchase 2.9 million shares of common stock issued to affiliates of Shell for the Cook Inlet Acquisition. - In July 1999, the Company issued 6 million shares of common stock for its 50% interest in Spring Holding Company and for cash proceeds of $3.2 million which was used to reduce bank debt. - In September 1998, the Company issued 2.9 million common shares from treasury to affiliates of Shell for the Cook Inlet Acquisition. In July 1999, the Company repurchased these shares from Shell. - In April 1998, the Company sold 10.8 million shares of common stock. Net proceeds of $133.1 million were used to partially repay bank debt used to fund the East Texas Basin Acquisition. Treasury Stock Purchases. The Company often repurchases shares of its common stock as part of its strategic acquisition plans. The Company purchased on the open market 5.3 million shares at a cost of $41.4 million in 2000, 7,500 shares at a cost of $53,000 in 1999 and 6.5 million shares at a cost of $65.6 million in 1998. Through March 26, 2001, 4.3 million shares remain under the May 2000 Board of Directors' authorization to purchase an additional 4.5 million shares. Conversion of Preferred Stock. In January 2001, the Company sent notice to preferred stockholders that it would redeem all outstanding shares on February 16, 2001 at a price of $25.94 per share plus accrued and unpaid dividends. Prior to the redemption date, 1.1 million outstanding shares of preferred stock were converted into 3.5 million common shares. Investment in Equity Securities. In 1998, the Company purchased what it believed to be undervalued oil and gas reserves by acquiring common stock of publicly traded independent oil and gas producers at a total cost of $167.7 million. For accounting purposes, the Company considered equity securities purchased in 1998 to be trading securities since they 21 were purchased with the intent to resell in the near future, and therefore recognized unrealized investment gains and losses in the income statements. After selling a portion of these securities in 1998 and 1999, the Company sold its remaining investment in equity securities in 2000 for $43.7 million. The Company recognized a $13.3 million gain in 2000, and losses of $1.1 million in 1999 and $93.7 million in 1998 related to this investment. Derivative fair value loss. During 2000, the Company recorded a $55.8 million loss on call options which the Company sold in 1999 related to its hedging activities. Because written call options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. A current liability of $53.8 million related to this loss is recorded in the consolidated balance sheet at December 31, 2000. See "Accounting Changes" below. Incentive Compensation. Incentive compensation results from stock appreciation right, performance share and royalty trust option awards, and subsequent changes in the Company's stock price. In 2000, incentive compensation totaled $26.1 million, which was primarily related to performance share grants and royalty trust option exercises. Incentive compensation was not significant in 1999. In 1998, incentive compensation totaled $1.3 million, which included non-cash performance share compensation of $1.6 million, partially offset by a reduction in stock appreciation right compensation of $300,000. As of December 31, 2000, there were 85,000 performance shares outstanding that vested when the common stock price closed above $30.00 on March 9, 2001, and 13,500 performance shares that vest in increments of 4,500 in each of 2001, 2002 and 2003. On March 9, 2001, an additional 77,000 performance shares were issued that vest when the stock price closes above $32.50. Product Prices. In addition to supply and demand, oil and gas prices are affected by seasonal, political and other fluctuations the Company generally cannot control or predict. Crude oil prices are generally determined by global supply and demand. Starting at about $15 per barrel, crude oil prices declined throughout 1998, dropping to a posted West Texas Intermediate ("WTI") price of $8.00 per barrel in December 1998, the lowest level since 1978. Oil prices increased in 1999 because of production cuts by OPEC and other leading oil exporters, reduced inventories and anticipated increased demand. Despite OPEC production increases in 2000, increased demand has sustained higher prices. In September 2000, posted WTI prices reached $34.25, their highest levels since the 1990 Persian Gulf War. In response to lower prices in 2001 caused by lagging demand, OPEC members announced their resolve to maintain higher oil prices through production cuts when needed. The Company uses commodity price hedging instruments to reduce its exposure to oil price fluctuations. Including the effect of these hedging instruments, the Company's average oil price decreased from $28.72 to $27.07 in 2000 and from $17.37 to $16.94 in 1999. Based on 2000 production, the Company estimates that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $4.5 million change in 2001 annual operating cash flow. Natural gas prices are influenced by North American supply and demand, which is often dependent upon weather conditions. Natural gas competes with alternative energy sources as a fuel for heating and the generation of electricity. Gas prices were approximately $2.00 per MMBtu in January 1998 and remained lower throughout the year because of mild winters in the central and eastern U.S. Cooler spring weather and lower industry production levels strengthened gas prices in 1999 and, after declining briefly at the end of 1999, continued to strengthen in 2000. The combination of lower domestic productive capacity, reduced storage and increased summer and winter demand have resulted in higher natural gas prices with increased volatility. NYMEX gas prices reached a record high of $10.10 in December 2000. At March 15, 2001, the average NYMEX price for the following 12 months was $5.08 per MMBtu. The Company uses commodity price hedging instruments to reduce its exposure to gas price fluctuations. Including the effect of these hedging instruments, the Company's average gas price decreased from $3.70 to $3.38 in 2000 and from $2.18 to $2.13 in 1999. Based on 2000 production, the Company estimates that a $0.10 per Mcf increase or decrease in the average gas sales price would result in approximately an $11 million change in 2001 annual operating cash flow. However, a significant portion of the Company's gas production through March 2002 is hedged by contracts that effectively fix prices. See Note 8 to the Consolidated Financial Statements. Impairment Provision. During 1998, the Company recorded an impairment provision on producing properties of $2 million before income tax. This impairment provision was determined based on an assessment of recoverability of net property costs from estimated future net cash flows from those properties. Estimated future net cash flows are based on management's best estimate of projected oil and gas reserves and prices. If oil and gas prices significantly decline, the Company may be required to record impairment provisions in the future, which could be material. 22 Results of Operations 2000 Compared to 1999 For the year 2000, earnings available to common stock were $115.2 million compared with earnings available to common stock of $45 million for 1999. The 2000 earnings include a $7.3 million after-tax gain from the sale of Hugoton Royalty Trust units, a $13.1 million after-tax gain on sale of properties, an $8.8 million after-tax gain on investment in equity securities, a $17.3 million after-tax charge for incentive compensation and a $36.8 after-tax loss on the change in derivative fair value. The 1999 earnings include a $26.8 million after-tax gain from the sale of Hugoton Royalty Trust units, a $4.2 million after-tax gain on sale of properties, and an $800,000 after-tax loss on investment in equity securities. Excluding these gains and losses from asset sales and incentive compensation, earnings for 2000 were $140.1 million, compared with $14.8 million for 1999. Revenues for 2000 were $600.9 million, or 76% above 1999 revenues of $341.3 million. Oil revenue increased $41.6 million, or 48%, because of a 60% increase in oil prices from an average of $16.94 per Bbl in 1999 to $27.07 in 2000 (see "General - Product Prices" above), partially offset by a 7% decrease in oil production. Decreased production was primarily because of the 2000 property sales. Gas and natural gas liquids revenue increased $217.8 million, or 91%, because of a 20% increase in gas production, a 22% increase in natural gas liquids production, a 59% increase in gas prices from an average of $2.13 per Mcf in 1999 to $3.38 in 2000 and a 66% increase in natural gas liquids prices from an average price of $11.80 per Bbl in 1999 to $19.61 in 2000 (see "General- Product Prices" above). Increased gas and natural gas liquids production was attributable to the 1999 acquisitions and the 1999 and 2000 development programs. Gas gathering, processing and marketing revenues increased $5.5 million primarily because of higher gas and natural gas liquids prices, increased margin and increased volumes from the 1999 acquisitions. Other revenues were $5.3 million lower primarily because of decreased net gains on sale of properties. Expenses for 2000 totaled $388.7 million as compared with total 1999 expenses of $245.9 million. Most expenses increased in 2000 primarily because of the 1999 acquisitions and the 1999 and 2000 development programs. Production expense increased $10.9 million, or 14%, because of increased production related to the 1999 acquisitions and 1999 and 2000 development programs. Production expense per Mcfe remained flat at $0.53. The Company's 2000 exploration expense of $1 million, which was predominantly geological and geophysical costs, remained about the same as 1999. Taxes, transportation and other deductions increased 68% or $23 million because of increased oil and gas revenues, as well as increased transportation, compression and other charges related to the 1999 acquisitions and the 1999 and 2000 development programs. Taxes, transportation and other per Mcfe increased 52% from $0.23 to $0.35 because of increased prices and other deductions. Depreciation, depletion and amortization ("DD&A") increased $17.4 million, or 16%, primarily because of the 1999 acquisitions and the 1999 and 2000 development programs. On an Mcfe basis, DD&A increased slightly from $0.78 in 1999 to $0.79. General and administrative expense increased $35.4 million, or 251% because of incentive compensation of $26.1 million and increased expenses from Company growth related to the 1999 acquisitions. Excluding incentive compensation, general and administrative expense per Mcfe increased from $0.10 in 1999 to $0.14 in 2000. Interest expense increased $14.7 million, or 23%, primarily because of a 7% increase in weighted average borrowings and an 8% increase in the weighted average interest rate. Interest classified as part of the gain (loss) on investment in equity securities decreased $4.6 million from 1999. Interest expense per Mcfe increased from $0.45 in 1999 to $0.48 in 2000. 23 1999 Compared to 1998 For the year 1999, earnings available to common stock were $45 million compared with a loss available to common stock of $71.5 million for 1998. The 1999 earnings include a $26.8 million after-tax gain from the sale of Hugoton Royalty Trust units, a $4.2 million after-tax gain on sale of properties and an $800,000 after-tax loss on investment in equity securities. The 1998 loss includes a $61.8 million after-tax loss related to the Company's investment in equity securities, a $500,000 after-tax gain on sale of properties, a $1.3 million after-tax impairment write-off of producing properties and a $900,000 after-tax charge for incentive compensation. Excluding these gains and losses from investments and asset sales and charges for impairment and incentive compensation, earnings for 1999 were $14.8 million, compared with an $8 million loss for 1998. Revenues for 1999 were $341.3 million, or 37% above 1998 revenues of $249.5 million. Oil revenue increased $30.4 million, or 54%, because of an 11% increase in oil production and a 39% increase in oil prices from an average of $12.21 per Bbl in 1998 to $16.94 in 1999 (see "General - Product Prices" above). Increased production was primarily because of the 1998 acquisitions. Gas and natural gas liquids revenue increased $56.5 million, or 31%, because of a 25% increase in gas production, a 3% increase in gas prices and a 55% increase in natural gas liquids prices from an average price of $7.62 per Bbl in 1998 to $11.80 in 1999 (see "General - Product Prices" above). Increased gas production was attributable to the 1998 and 1999 acquisitions and development programs. Gas gathering, processing and marketing revenues increased $1.2 million primarily because of higher gas and natural gas liquids prices, increased margin and increased volumes from the 1999 acquisitions. Other revenues were $3.7 million higher primarily because of increased net gains on sale of properties, partially offset by decreased lawsuit settlement receipts. Expenses for 1999 totaled $245.9 million as compared with total 1998 expenses of $209.2 million. Most expenses increased in 1999 primarily because of the 1998 and 1999 acquisitions and development programs. Production expense increased $13 million, or 21%, because of increased production. Production expense per Mcfe remained flat at $0.53. The Company lowered its exploration budget for 1999, resulting in a $7.1 million reduction in exploration expense, which is predominantly geological and geophysical costs. Taxes, transportation and other deductions increased 16% or $4.6 million because of increased oil and gas revenues, as well as increased transportation, compression and other charges related to the 1998 and 1999 acquisitions. Taxes, transportation and other per Mcfe decreased 8% from $0.25 to $0.23 because of decreased property taxes and a lower production tax rate associated with production from the 1999 acquisitions. Depreciation, depletion and amortization increased $28.8 million, or 34%, primarily because of the 1998 and 1999 acquisitions and development programs. On an Mcfe basis, DD&A increased from $0.70 in 1998 to $0.78 in 1999 primarily because of the higher cost per Mcfe of the 1998 and 1999 acquisitions. General and administrative expense increased $600,000, or 5%, because of increased expenses from Company growth related to the 1998 and 1999 acquisitions. Excluding incentive compensation, general and administrative expense per Mcfe remained at $0.10 in 1999. Interest expense increased $12.1 million, or 23%, primarily because of a comparable increase in weighted average borrowings to partially fund the 1998 and 1999 acquisitions. Interest related to investment in equity securities has been classified as part of the loss on investment in equity securities. Interest expense per Mcfe increased slightly from $0.44 in 1998 to $0.45 in 1999. 24 Liquidity and Capital Resources The Company's primary sources of liquidity are cash flow from operating activities, producing property sales, including sales of royalty trust units, public offerings of equity and debt, and bank debt. Other than for operations, the Company's cash requirements are generally for the acquisition, exploration and development of oil and gas properties, and debt and dividend payments. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. The Company believes that its sources of liquidity are adequate to fund its cash requirements in 2001. Cash provided by operating activities was $377.4 million in 2000, compared with cash provided by operating activities of $133.3 million in 1999 and $53.9 million cash used by operations in 1998. Fluctuations during this three-year period were primarily because of purchases of equity securities and lower product prices in 1998 and increased prices and production from acquisitions and development activity in 1999 and 2000. Before changes in operating assets and liabilities and exploration expense, cash flow from operations was $344.6 million in 2000, $132.7 million in 1999 and $78.5 million in 1998. Financial Condition Total assets increased 8% from $1.5 billion at December 31, 1999 to $1.6 billion at December 31, 2000, primarily because of higher product prices and Company growth related to the 1999 acquisitions. As of December 31, 2000, total capitalization of the Company was $1.3 billion, of which 61% was long-term debt. Capitalization at December 31, 1999 was also $1.3 billion, but 78% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 1999 to 2000 is because of repayment of debt from cash flow and the sale of common stock. Working Capital The Company generally uses available cash to reduce bank debt and, therefore, does not maintain large cash and cash equivalent balances. Short-term liquidity needs are satisfied by bank commitments under the loan agreement (see "Financing" below). Because of this, and since the Company's principal source of operating cash flows (i.e., proved reserves to be produced in the following year) cannot be reported as working capital, the Company often has low or negative working capital. The decrease in working capital from $39.3 million at December 31, 1999 to negative working capital of $25.3 million at December 31, 2000 was primarily attributable to the sale of equity security investments and increased current liabilities, net of the increase in current deferred income tax benefit, related to the derivative fair value loss. Included in other current liabilities at December 31, 2000 is a $53.8 million derivative loss accrual for the fair value of call options sold in 1999 related to the Company's hedging activities. Beginning January 1, 2001, the Company will also accrue fair value losses related to unrealized hedge derivative losses and a gas delivery contract. See "Accounting Changes" below. The Company expects that any cash settlement of these derivative losses should be offset by increased cash flows from the Company's sale of related production. Therefore, the Company believes that substantially all derivative fair value gains and losses are offset by changes in value of its natural gas reserves. This offsetting change in gas reserve value, however, is not reflected in working capital. Prior to their sale, equity securities owned by the Company had been held in a PaineWebber broker account and provided support for officer margin debt. As of March 2001, officer margin debt balances related to Company common stock were fully repaid, and the margin support agreements were terminated because they were no longer needed. See Note 3 to Consolidated Financial Statements. Financing In May 2000, the Company entered a new revolving credit agreement with commercial banks with a commitment of $800 million. Proceeds of this loan agreement were used to refinance the Company's previous senior credit facility and to fully repay a $25 million term loan and the separate bank debt of the Company's subsidiaries, Spring Holding Company and Summer Acquisition Company. In June 2000, the loan agreement was amended to allow the Company to issue letters of credit. Any letters of credit outstanding reduce the borrowing capacity under the revolving credit facility. As of December 31, 2000, letters of credit outstanding totaled $33 million. Borrowings at 25 December 31, 2000 under the loan agreement were $469 million with unused borrowing capacity of $298 million. The borrowing base is redetermined annually based on the value and expected cash flow of the Company's proved oil and gas reserves. If borrowings exceed the redetermined borrowing base, the banks may require that the excess be repaid within a year. Based on reserve values at December 31, 2000 and parameters specified by the banks, the borrowing base supports borrowings in excess of the $800 million commitment. Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at any time without penalty. The Company periodically renegotiates the loan agreement to increase the borrowing commitment and extend the revolving facility. In February 2001, the loan agreement was amended to allow the repurchase of the Company's subordinated debt and to increase commodity hedging limits. On January 3, 2001, the Company purchased primarily gas-producing properties in East Texas and Louisiana for $115 million, of which $11.6 million had been paid in 2000. This acquisition was funded through borrowings under the loan agreement which are expected to be repaid from cash flow during the first six months of 2001. The 1999 and 1998 acquisitions were partially funded by the sale and issuance of common stock and cash flow from operations. The 1999 acquisitions were also partially funded by contributions from Lehman, the Company's equity partner until the Company later purchased Lehman's interest in these acquisitions. These transactions are described under "General" above. See also "Capital Expenditures" below. Capital Expenditures Because of their size, the 1999 acquisitions were made jointly with Lehman as a 50% equity partner. Pursuant to its call option, the Company acquired Lehman's interest in the Spring Holding Acquisition in September 1999. The Company exercised its option to purchase Lehman's interest in the Ocean Energy Acquisition on March 31, 2000 for $111 million, funded primarily by the proceeds from sales of property and equity security investments. The Company plans to fund any future property acquisitions through a combination of cash flow from operations and proceeds from asset sales, bank debt, public equity or debt transactions. There are no restrictions under the Company's revolving credit agreement that would affect the Company's ability to use its remaining borrowing capacity for acquisitions of producing properties. In February 2000, the Board of Directors authorized the repurchase of 3.8 million shares of the Company's common stock. Upon completion of repurchases under this authorization, the Board of Directors authorized the repurchase of an additional 4.5 million shares in May. During 2000, the Company repurchased 5.3 million shares of its common stock at a cost of $41.4 million, including 1.3 million shares repurchased under a prior Board authorization. As of March 26, 2001, 4.3 million shares are available for repurchase under the May 2000 Board authorization. In 2000, exploration and development cash expenditures totaled $155.4 million compared with $91.6 million in 1999. The Company has budgeted $250 million for the 2001 development program. As it has done historically, the Company expects to fund the 2001 development program with cash flow from operations. Since there are no material long-term commitments associated with this budget, the Company has the flexibility to adjust its actual development expenditures in response to changes in product prices, industry conditions and the effects of the Company's acquisition and development programs. A minor portion of the Company's existing properties are operated by third parties which control the timing and amount of expenditures required to exploit the Company's interests in such properties. Therefore, the Company cannot assure the timing or amount of these expenditures. To date, the Company has not spent significant amounts to comply with environmental or safety regulations, and it does not expect to do so during 2001. However, developments such as new regulations, enforcement policies or claims for damages could result in significant future costs. Dividends The Board of Directors declared quarterly dividends of $0.0267 per common share in 1998, $0.0067 per common share from 1999 through second quarter 2000 and $0.01 per common share for the third and fourth quarters of 2000. The Company's ability to pay dividends is dependent upon available cash flow, as well as other factors. In 26 addition, the Company's bank loan agreement restricts the amount of common stock dividends to 25% of cash flow from operations, as defined, for the last four quarters. Cumulative dividends on Series A convertible preferred stock are paid quarterly, when declared by the Board of Directors, based on an annual rate of $1.5625 per share. Pursuant to the Company's notice of preferred stock redemption, all preferred stock was converted into common shares prior to March 2001. Accounting Changes Effective January 1, 2001, the Company has adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the income statement. Change in fair value of effective cash flow hedges are recorded as a component of other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. Physical delivery contracts which cannot be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives. However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative. The Company accounted for adoption of SFAS No. 133 on January 1, 2001 by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in accounting principle, and an unrealized after-tax loss of $67.3 million in other comprehensive income. The charge to the income statement is primarily related to the Company's physical delivery contract to sell 35,500 Mcf of natural gas per day from 2002 through July 2005 at crude oil-based prices. The unrealized loss is related to the derivative fair value of cash flow hedges. See Note 8 to Consolidated Financial Statements. Amounts recorded on the balance sheet at January 1, 2001 were a $103.6 million current liability, a $2.2 million long-term asset and a $70.8 million long-term liability related to the fair value of derivatives, and a current deferred tax asset of $36.3 million and a reduction to the long-term tax liability of $24 million for the related tax benefits. As oil and gas prices fluctuate, the Company will recognize a derivative fair value gain or loss in its consolidated income statement related to the gas physical delivery contract with crude oil-based pricing, as well as written call options. The opportunity loss, related to market gas prices exceeding the prices provided by these contracts, is immediately recognized as a loss in derivative fair value in the income statement. This contrasts with opportunity losses on hedge derivative contracts which are recorded as an unrealized loss in other comprehensive income and later recognized in the income statement when the related sale occurs. Since there is no net cash settlement expected under the gas physical delivery contract, any losses recognized under this contract will be reversed into income when gas is delivered. In all other cases, derivative losses should be offset by increased cash flows from the Company's later sale of related production. Accordingly, the Company believes that substantially all derivative fair value gains and losses will be offset by changes in the value of its natural gas reserves. This offsetting change in gas reserve value, however, is not reflected in the Company's financial statements. See Item 7A, "Commodity Price Risk" for the effect of price changes on derivative fair value gains and losses. Production Imbalances The Company has gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on jointly owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well, or by cash payment by the overproduced party to the underproduced party. The Company uses the entitlement method of accounting for natural gas sales. At December 31, 2000, the Company's consolidated balance sheet includes a net current asset of $2.5 million for a net underproduced balancing position of 911,000 Mcf of natural gas, and a net long-term liability of $3.7 million for an overproduced balancing position of 3,581,000 Mcf of natural gas, net of an underproduced balancing position of 10,062,000 Mcf of carbon dioxide. Production imbalances do not have, and are not expected to have, a significant impact on the Company's liquidity or operations. 27 Forward-Looking Statements Certain information included in this annual report and other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by the Company, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company's operations and the oil and gas industry. Such forward- looking statements may be or may concern, among other things, capital expenditures, cash flow, drilling activity, acquisition and development activities, pricing differentials, operating costs, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, regulatory matters and competition. Such forward-looking statements are based on management's current plans, expectations, assumptions, projections and estimates and are identified by words such as "expects," "intends," "plans," "projects," "predicts," "anticipates," "believes," "estimates," "goal," "should," "could," "assume," and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. Among the factors that could cause actual results to differ materially are: - crude oil and natural gas price fluctuations, - changes in interest rates, - the Company's ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling, - higher than expected production costs and other expenses, - potential delays or failure to achieve expected production from existing and future exploration and development projects, - volatility of crude oil, natural gas and hydrocarbon-based financial derivative prices, - basis risk and counterparty credit risk in executing commodity price risk management activities, - potential liability resulting from pending or future litigation, - competition in the oil and gas industry as well as competition from other sources of energy. In addition, these forward-looking statements may be affected by general domestic and international economic and political conditions. Item 7A. Quantitative and Qualitative Disclosures about Market Risk The Company only enters derivative financial instruments in conjunction with its hedging activities. These instruments principally include interest rate swap agreements and commodity futures, swaps and option agreements. These financial and commodity-based derivative contracts are used to limit the risks of interest rate fluctuations and natural gas and crude oil price changes. Gains and losses on these derivatives are generally offset by losses and gains on the respective hedged exposures. The Board of Directors has adopted a policy governing the use of derivative instruments, which requires that all derivatives used by the Company relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. The policy also requires review and approval by the Chairman or the Executive Vice President - Administration of all risk management programs using derivatives and all derivative transactions. These programs are also reviewed at least annually by the Board of Directors. 28 Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and product prices. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations. Interest Rate Risk The Company is exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2000, the Company's variable rate debt had a carrying value of $469 million, which approximated its fair value, and the Company's fixed rate debt had a carrying value of $300 million and an approximate fair value of $305 million. Assuming a one percent, or 100-basis point, change in interest rates at December 31, 2000, the fair value of the Company's fixed rate debt would change by approximately $16.4 million. The Company attempts to balance the benefit of lower cost variable rate debt that has inherent increased risk with more expensive fixed rate debt that has less market risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate subordinated debt, as well as the use of interest rate swaps. The following table shows the carrying amount and fair value of long-term debt and interest rate swaps, and the hypothetical change in fair value that would result from a 100-basis point change in interest rates. The hypothetical change in fair value could result in a gain or a loss depending on an increase or decrease in the interest rate.
Hypothetical Carrying Fair Change in (in thousands) Amount Value Fair Value ---------- ---------- ------------ December 31, 2000 Long-term debt....... $(769,000) $(774,000) $16,389 Interest rate swaps.. 473 2,651 1,484 December 31, 1999 Long-term debt....... $(991,100) $(981,540) $16,771 Interest rate swaps.. 218 2,503 2,237
Commodity Price Risk The Company hedges a portion of its price risks associated with its crude oil and natural gas sales. As of December 31, 2000, the Company had outstanding gas futures contracts, swap agreements and gas basis swap agreements. Gas futures contracts and swap agreements would have had a total fair value loss of approximately $112.8 million at December 31, 2000 and $2.7 million at December 31, 1999. Basis swap agreements had a fair value gain of $3.9 million at December 31, 2000 and a fair value loss of $1.1 million at December 31, 1999. The aggregate effect of a hypothetical 10% change in gas prices and basis would result in a change of approximately $19.9 million in the fair value of gas futures contracts and swap agreements and approximately $483,000 in the fair value of basis swap agreements at December 31, 2000. This sensitivity does not include the effects of commodity contracts, such as physical product delivery contracts, that cannot be settled in cash or another financial instrument. See Note 8 to Consolidated Financial Statements. In conjunction with its hedging activities, the Company sold call options to sell future gas production at certain ceiling prices. Call options outstanding had a fair value loss of $44.5 million at December 31, 2000 and $300,000 at December 31, 1999. The aggregate effect of a hypothetical 10% change in gas prices and basis would result in a change of approximately $8.1 million in the fair value of these options at December 31, 2000. Changes in the fair value of these options are recognized in the consolidated income statements since they do not qualify for hedge accounting. See Note 7 to Consolidated Financial Statements. The Company has entered a physical delivery contract to sell 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract is priced based on crude oil, which is not clearly and closely associated with natural gas prices, it must be accounted for as a non-hedge derivative financial instrument under SFAS No. 133 beginning January 1, 2001. See 29 Note 8 to Consolidated Financial Statements and "Accounting Changes" above. The pre-tax fair value loss of this contract at January 1, 2001 is $70.8 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $15.8 million in the fair value of this contract, while a 10% change in crude oil prices would result in a change of approximately $8.7 million. 30 Item 8. Financial Statements and Supplementary Data The following financial statements and supplementary information are included under Item 14(a):
Page ---- Consolidated Balance Sheets......................... 33 Consolidated Income Statements...................... 34 Consolidated Statements of Cash Flows............... 35 Consolidated Statements of Stockholders' Equity..... 36 Notes to Consolidated Financial Statements.......... 37 Selected Quarterly Financial Data (Note 15 to Consolidated Financial Statements).... 57 Information about Oil and Gas Producing Activities (Note 16 to Consolidated Financial Statements).... 58 Report of Independent Public Accountants............ 61
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 Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management Item 13. Certain Relationships and Related Transactions Except for the portion of Item 10 relating to Executive Officers of the Registrant which is included in Part I of this Report, the information called for by Items 10 through 13 is incorporated by reference from the Company's Notice of Annual Meeting and Proxy Statement to be filed with the Commission no later than April 30, 2001. 31 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:
Page ---- 1. Financial Statements: Consolidated Balance Sheets at December 31, 2000 and 1999............. 33 Consolidated Income Statements for the years ended December 31, 2000, 1999 and 1998................................... 34 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998................................... 35 Consolidated Statements of Stockholders' Equity for the years ended December 31, 2000, 1999 and 1998.................................... 36 Notes to Consolidated Financial Statements............................ 37 Report of Independent Public Accountants.............................. 61 2. Financial Statement Schedules: All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated financial statements.
(b) Reports on Form 8-K The Company filed the following reports on Form 8-K during the quarter ended December 31, 2000 and through March 30, 2001: On November 20, 2000, the Company filed a report on Form 8-K to disclose financial results for the third quarter of 2000 and the Company's sale of 6 million shares of its common stock. On December 20, 2000, the Company filed a report on Form 8-K to announce that it had entered into a definitive agreement to buy primarily gas-producing properties in East Texas and Louisiana and had increased its 2001 capital budget by $50 million to $250 million. On January 12, 2001, the Company filed a report on Form 8-K regarding its completion of the previously announced acquisition of primarily gas-producing properties in East Texas and Louisiana. (c) Exhibits See Index to Exhibits at page 63 for a description of the exhibits filed as a part of this report. 32 CROSS TIMBERS OIL COMPANY Consolidated Balance Sheets --------------------------------------------------------------------------------
(in thousands, except shares) December 31 ------------------------ 2000 1999 ---------- ---------- ASSETS Current Assets: Cash and cash equivalents......................................... $ 7,438 $ 5,734 Accounts receivable, net.......................................... 158,826 68,998 Investment in equity securities................................... - 29,052 Deferred income tax benefit....................................... 17,098 4,168 Other current assets.............................................. 10,075 5,540 ---------- ---------- Total Current Assets............................................ 193,437 113,492 ---------- ---------- Property and Equipment, at cost - successful efforts method: Producing properties.............................................. 1,732,017 1,635,883 Undeveloped properties............................................ 6,460 10,358 Gas gathering and other........................................... 38,340 32,902 ---------- ---------- Total Property and Equipment..................................... 1,776,817 1,679,143 Accumulated depreciation, depletion and amortization.............. (419,443) (340,063) ---------- ---------- Net Property and Equipment...................................... 1,357,374 1,339,080 ---------- ---------- Other Assets....................................................... 32,879 16,817 ---------- ---------- Loans to Officers.................................................. 8,214 7,692 ---------- ---------- TOTAL ASSETS....................................................... $1,591,904 $1,477,081 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and accrued liabilities.......................... $ 153,581 $ 68,937 Payable to royalty trusts......................................... 8,577 2,739 Other current liabilities......................................... 56,593 2,542 ---------- ---------- Total Current Liabilities....................................... 218,751 74,218 ---------- ---------- Long-term Debt..................................................... 769,000 991,100 ---------- ---------- Deferred Income Taxes Payable...................................... 82,476 25,975 ---------- ---------- Other Long-term Liabilities........................................ 24,310 7,959 ---------- ---------- Commitments and Contingencies (Note 6) Minority Interest in Consolidated Subsidiary....................... - 100,012 ---------- ---------- Stockholders' Equity: Series A convertible preferred stock ($.01 par value, 25,000,000 shares authorized, 1,088,663 and 1,138,729 shares issued, at liquidation value of $25)..................................... 27,217 28,468 Common stock ($.01 par value, 100,000,000 shares authorized, 82,586,830 and 87,282,751 shares issued)......................... 826 873 Additional paid-in capital........................................ 435,735 396,277 Treasury stock (5,031,040 and 13,949,073 shares).................. (50,829) (119,387) Retained earnings (deficit)....................................... 84,418 (28,414) ---------- ---------- Total Stockholders' Equity...................................... 497,367 277,817 ---------- ---------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY......................... $1,591,904 $1,477,081 ========== ==========
See accompanying notes to consolidated financial statements. 33 CROSS TIMBERS OIL COMPANY Consolidated Income Statements --------------------------------------------------------------------------------
(in thousands, except per share data) Year Ended December 31 ------------------------------- 2000 1999 1998 -------- -------- --------- REVENUES Oil and condensate................................................... $128,194 $ 86,604 $ 56,164 Gas and natural gas liquids.......................................... 456,814 239,056 182,587 Gas gathering, processing and marketing.............................. 16,123 10,644 9,438 Other................................................................ (280) 4,991 1,297 -------- -------- --------- Total Revenues....................................................... 600,851 341,295 249,486 -------- -------- --------- EXPENSES Production........................................................... 86,988 76,110 63,148 Taxes, transportation and other...................................... 56,696 33,681 29,105 Exploration.......................................................... 1,047 904 8,034 Depreciation, depletion and amortization............................. 129,807 112,364 83,560 Impairment........................................................... - - 2,040 Gas gathering and processing......................................... 8,930 8,743 8,360 General and administrative........................................... 49,460 14,091 13,479 Derivative fair value loss........................................... 55,821 - - Trust development costs.............................................. - - 1,498 -------- -------- --------- Total Expenses....................................................... 388,749 245,893 209,224 -------- -------- --------- OPERATING INCOME..................................................... 212,102 95,402 40,262 -------- -------- --------- OTHER INCOME (EXPENSE) Gain on significant property divestitures............................ 29,965 40,566 - Gain (loss) on investment in equity securities....................... 13,279 (1,149) (93,719) Interest expense, net................................................ (78,914) (64,214) (52,113) -------- -------- --------- Total Other Income (Expense)......................................... (35,670) (24,797) (145,832) -------- -------- --------- INCOME (LOSS) BEFORE INCOME TAX AND MINORITY INTEREST............................................... 176,432 70,605 (105,570) Income Tax Expense (Benefit)......................................... 59,380 23,965 (35,851) Minority Interest in Net (Income) Loss of Consolidated Subsidiaries.. (59) 103 - -------- -------- --------- NET INCOME (LOSS).................................................... 116,993 46,743 (69,719) Preferred stock dividends............................................ 1,758 1,779 1,779 -------- -------- --------- EARNINGS (LOSS) AVAILABLE TO COMMON STOCK............................ $115,235 $ 44,964 $ (71,498) ======== ======== ========= EARNINGS (LOSS) PER COMMON SHARE Basic............................................................... $1.62 $0.64 $(1.10) ======== ======== ========= Diluted............................................................. $1.55 $0.63 $(1.10) ======== ======== ========= Weighted Average Common Shares Outstanding........................... 71,154 70,228 65,094 ======== ======== =========
See accompanying notes to consolidated financial statements. 34 CROSS TIMBERS OIL COMPANY Consolidated Statements of Cash Flows --------------------------------------------------------------------------------
(in thousands) Year Ended December 31 --------------------------------- 2000 1999 1998 --------- --------- --------- OPERATING ACTIVITIES Net income (loss)............................................................... $ 116,993 $ 46,743 $ (69,719) Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: Depreciation, depletion and amortization.................................... 129,807 112,364 83,560 Impairment.................................................................. - - 2,040 Non-cash incentive compensation............................................. 25,790 93 1,141 Deferred income tax......................................................... 58,993 23,657 (35,744) (Gain) loss on investment in equity securities and from sale of properties.. (45,578) (51,802) 86,628 Non-cash loss in derivative fair value...................................... 54,512 - - Minority interest in net income (loss) of consolidated subsidiaries......... 59 (103) - Other non-cash items........................................................ 3,015 827 2,540 Changes in operating assets and liabilities (a)............................. 33,830 1,522 (124,322) --------- --------- --------- Cash Provided (Used) by Operating Activities.................................... 377,421 133,301 (53,876) --------- --------- --------- INVESTING ACTIVITIES Proceeds from sale of Hugoton Royalty Trust units............................... - 148,570 - Proceeds from sale of other property and equipment.............................. 77,119 110,500 2,494 Property acquisitions........................................................... (45,648) (270,226) (296,390) Purchase of Spring Holding Company.............................................. - (42,540) - Development costs............................................................... (154,382) (90,725) (69,356) Gas gathering and other additions............................................... (11,033) (10,479) (7,517) (Loans to) repayments from officers............................................. 60 (1,470) (5,795) --------- --------- --------- Cash Used by Investing Activities............................................... (133,884) (156,370) (376,564) --------- --------- --------- FINANCING ACTIVITIES Proceeds from short- and long-term debt......................................... 523,400 256,400 877,900 Payments on short- and long-term debt........................................... (745,500) (339,262) (496,938) Purchase of minority interest................................................... (100,071) (42,385) - Contributions from minority interests........................................... - 142,500 - Common stock offering........................................................... 126,125 29,668 133,113 Dividends....................................................................... (3,891) (4,950) (8,460) Purchases of treasury stock and other........................................... (41,896) (25,501) (66,658) --------- --------- --------- Cash Provided (Used) by Financing Activities.................................... (241,833) 16,470 438,957 --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................................ 1,704 (6,599) 8,517 Cash and Cash Equivalents, January 1............................................ 5,734 12,333 3,816 --------- --------- --------- Cash and Cash Equivalents, December 31.......................................... $ 7,438 $ 5,734 $ 12,333 ========= ========= ========= (a) Changes in Operating Assets and Liabilities Accounts receivable....................................................... $ (90,921) $ (8,227) $ (7,022) Investment in equity securities........................................... 43,746 20,180 (131,809) Other current assets...................................................... (4,535) (32) (1,513) Other assets.............................................................. (15,535) - - Current liabilities....................................................... 82,392 (11,628) 16,022 Other long-term liabilities............................................... 18,683 1,229 - --------- --------- --------- Decrease (Increase) in Operating Assets and Liabilities..................... $ 33,830 $ 1,522 $(124,322) ========= ========= =========
See accompanying notes to consolidated financial statements. 35 CROSS TIMBERS OIL COMPANY Consolidated Statements of Stockholders' Equity --------------------------------------------------------------------------------
(in thousands, except per share amounts) Additional Retained Preferred Common Paid-in Treasury Earnings Stock Stock Capital Stock (Deficit) Total ----------- --------- --------- ---------- --------- --------- Balances, December 31, 1997.................. $28,468 $695 $210,722 $ (76,656) $ 7,014 $170,243 Sale of common stock......................... - 108 133,005 - - 133,113 Issuance/vesting of performance shares....... - 1 1,804 (536) - 1,269 Stock option exercises....................... - 7 2,984 (483) - 2,508 Treasury stock purchases..................... - - - (65,575) - (65,575) Treasury stock issued........................ - - 13,741 24,695 - 38,436 Common stock dividends ($0.11 per share)..... - - - - (7,022) (7,022) Preferred stock dividends ($1.56 per share).. - - - - (1,779) (1,779) Net loss..................................... - - - - (69,719) (69,719) ---------- ---- -------- --------- -------- -------- Balances, December 31, 1998.................. 28,468 811 362,256 (118,555) (71,506) 201,474 Issuance/sale of common stock................ - 60 45,640 - - 45,700 Issuance/vesting of performance shares....... - 2 231 - - 233 Stock option exercises....................... - - 95 (755) - (660) Treasury stock purchases..................... - - - (25,517) - (25,517) Treasury stock issued........................ - - (11,945) 25,440 - 13,495 Common stock dividends ($0.03 per share)..... - - - - (1,872) (1,872) Preferred stock dividends ($1.56 per share).. - - - - (1,779) (1,779) Net income................................... - - - - 46,743 46,743 ---------- ---- -------- --------- -------- -------- Balances, December 31, 1999.................. 28,468 873 396,277 (119,387) (28,414) 277,817 Sale of common stock from treasury........... - - 61,427 64,698 - 126,125 Issuance/vesting of performance shares....... - 8 18,244 (6,976) - 11,276 Stock option exercises....................... - 32 29,976 (4,933) - 25,075 Treasury stock purchases..................... - - - (55,758) - (55,758) Cancellation of shares....................... - (89) (71,438) 71,527 - - Common stock dividends ($0.03 per share)..... - - - - (2,403) (2,403) Preferred stock converted to common.......... (1,251) 2 1,249 - - - Preferred stock dividends ($1.56 per share).. - - - - (1,758) (1,758) Net income................................... - - - - 116,993 116,993 ---------- ---- -------- --------- -------- -------- Balances, December 31, 2000.................. $27,217 $826 $435,735 $ (50,829) $ 84,418 $497,367 ========== ==== ======== ========= ======== ========
See accompanying notes to consolidated financial statements. 36 CROSS TIMBERS OIL COMPANY Notes to Consolidated Financial Statements -------------------------------------------------------------------------------- 1. Organization and Summary of Significant Accounting Policies Cross Timbers Oil Company, a Delaware corporation, was organized in October 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986 through 1989. Cross Timbers Oil Company completed its initial public offering of common stock in May 1993. The accompanying consolidated financial statements include the financial statements of Cross Timbers Oil Company and its wholly owned subsidiaries ("the Company"). All significant intercompany balances and transactions have been eliminated in the consolidation. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the three-for-two stock splits effected on February 25, 1998 and September 18, 2000. The Company is an independent oil and gas company with production and exploration concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico, Wyoming, Alaska and Louisiana. The Company also gathers, processes and markets gas, transports and markets oil and conducts other activities directly related to its oil and gas producing activities. Comprehensive Income During the years ended December 31, 2000, 1999 and 1998, there were no reportable elements of comprehensive income other than net income. Property and Equipment The Company follows the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. The Company generally pursues acquisition and development of proved reserves as opposed to exploration activities. Most of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of producing properties from other oil and gas companies. Producing properties balances include costs of $66,823,000 at December 31, 2000 and $27,937,000 at December 31, 1999, related to wells in process of drilling. Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives which range from 3 to 40 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized. The estimated undiscounted cost, net of salvage value, of dismantling and removing major oil and gas production facilities, including necessary site restoration, are accrued using the unit-of-production method. If conditions indicate that long-term assets may be impaired, the carrying value of property and equipment is compared to management's future estimated pretax cash flow. If impairment is necessary, the asset carrying value is adjusted to fair value. Cash flow pricing estimates are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Impairment of individually significant undeveloped properties is assessed on a property-by-property basis, and impairment of other undeveloped properties is assessed and amortized on an aggregate basis. The Company recorded an impairment provision on producing properties of $2,040,000 before income tax in 1998. 37 Royalty Trusts The Company created Cross Timbers Royalty Trust in February 1991 and Hugoton Royalty Trust in December 1998 by conveying defined net profits interests in certain of the Company's properties. Units of both trusts are traded on the New York Stock Exchange. The Company makes monthly net profits payments to each trust based on revenues and costs from the related underlying properties. The Company owns 22.7% of Cross Timbers Royalty Trust units that it purchased on the open market in 1996 and 1997, and owns 54.3% of the Hugoton Royalty Trust following the sale of units in 1999 and 2000. The cost of the Company's interest in the trusts is included in producing properties. Amounts due the trusts, net of amounts retained by the Company's ownership of trust units, are deducted from the Company's revenues, taxes, production expenses and development costs. As of January 1, 1999, the Company no longer records the trusts' portion of development costs as an expense in the consolidated income statement. Cash and Cash Equivalents Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less. Investment in Equity Securities In accordance with Statement of Financial Accounting Standards ("SFAS") No. 115, Accounting for Certain Investments in Debt and Equity Securities, equity securities were recorded as trading securities since they were acquired principally for resale in the near future. Accordingly, this investment at December 31, 1999 is recorded as a current asset at market value, unrealized holding gains and losses are recognized in the consolidated income statements, and cash flows from purchases and sales of equity securities are included in cash provided (used) by operating activities in the consolidated statements of cash flows. Gains (losses) on trading securities and interest expense related to the cost of these investments are classified as other income (expense) in the consolidated income statements. See Note 2. Other Assets Other assets primarily include deferred debt costs that are amortized over the term of the related debt (Note 4) and the long-term portion of gas balancing receivable (see "Revenue Recognition" below). Other assets are presented net of accumulated amortization of $11,574,000 at December 31, 2000 and $7,252,000 at December 31, 1999. Derivatives The Company uses derivatives to hedge product price and interest rate risks, as opposed to their use for trading purposes. Gains and losses on commodity futures contracts are recognized in oil and gas revenues when the hedged transaction occurs. Amounts receivable or payable under interest swap agreements are recorded as adjustments to interest expense. Cash flows related to derivative transactions are included in operating activities. See Note 7. In conjunction with its hedging activities, the Company occasionally enters natural gas call options. Because options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectively provided by the call options, is recognized as a derivative fair value loss, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged production occurs, as prescribed by hedge accounting. Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138 (Note 7). SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the income statement. Changes in the fair value of effective cash flow hedges are recorded as a component of other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. Physical delivery contracts which cannot be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives. However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative (Note 8). 38 Revenue Recognition The Company uses the entitlement method of accounting for gas sales, based on the Company's net revenue interest in production. Accordingly, revenue is deferred when gas deliveries exceed the Company's net revenue interest, while revenue is accrued for under-deliveries. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. At December 31, 2000, the Company's consolidated balance sheet includes a net current asset of $2.5 million for a net underproduced balancing position of 911,000 Mcf of natural gas, and a net long-term liability of $3.7 million for an overproduced balancing position of 3,581,000 Mcf of natural gas, net of an underproduced balancing position of 10,062,000 Mcf of carbon dioxide. Gas Gathering, Processing and Marketing Revenues Gas produced by the Company and third parties is marketed by the Company to brokers, local distribution companies and end-users. Gas gathering and marketing revenues are recognized in the month of delivery based on customer nominations. Gas processing and marketing revenues are recorded net of cost of gas sold of $144.3 million for 2000, $66.2 million for 1999 and $56.3 million for 1998. These amounts are net of intercompany eliminations. Other Revenues Other revenues include gains and losses from sale of property and equipment. Excluding the gain on sale of significant property divestitures, including the sale of Hugoton Royalty Trust units (Note 13), the Company realized gains on sale of property and equipment of $920,000 in 2000, $6,390,000 in 1999 and $795,000 in 1998. Interest Expense Interest expense includes amortization of deferred debt costs and is presented net of interest income of $1,430,000 in 2000, $619,000 in 1999 and $91,000 in 1998, and net of capitalized interest of $3,488,000 in 2000, $1,353,000 in 1999 and $1,070,000 in 1998. Interest expense related to investment in equity securities has been classified as a component of gain (loss) on investment in equity securities (Note 2). Stock-Based Compensation In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation is recorded for stock options or other stock-based awards that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. Compensation related to performance share grants is recognized from the grant date until the performance conditions are satisfied. The pro forma effect of recording stock-based compensation at the estimated fair value of awards on the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, is disclosed in Note 12. Earnings per Common Share In accordance with SFAS No. 128, Earnings Per Share, the Company reports basic earnings per share, which excludes the effect of potentially dilutive securities, and diluted earnings per share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. See Note 10. Segment Reporting In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, the Company has identified only one operating segment, which is the exploration and production of oil and gas. All the Company's assets are located in the United States and all its revenues are attributable to United States customers. There were no sales to a single purchaser that exceeded 10% of total revenues in 2000, 1999 or 1998. 39 2. Investment in Equity Securities In 1998, the Company purchased what it believed to be undervalued oil and gas reserves through investments in publicly traded equity securities of select energy companies. After selling a portion of these securities in 1998 and 1999, the Company sold its remaining investment in equity securities in 2000 for $43.7 million, resulting in a gain of $13.3 million. The following are components of gain (loss) on investment in equity securities:
(in thousands) 2000 1999 1998 -------- -------- -------- Realized gains (losses) on sale of securities: Gains............................................ $ 4,683 $ 823 $ 887 Losses........................................... (35,523) (23,047) (15,706) -------- -------- -------- Net gains (losses)............................... (30,840) (22,224) (14,819) Changes in unrealized gains (losses)............... 45,535 27,070 (72,605) Interest expense related to investment in equity securities................................ (1,416) (5,995) (6,295) -------- -------- -------- Gains (losses) on investment in equity securities.. $ 13,279 $ (1,149) $(93,719) ======== ======== ========
3. Related Party Transactions Loans to Officers Pursuant to margin support agreements with each of six officers, the Company, with Board of Director authorization, agreed to use up to $15 million of the value of Cross Timbers Royalty Trust units owned by the Company and investment in equity securities, to provide margin support for the officers' broker accounts in which they held Company common stock. The Company also agreed to pay each officer's margin debt to the extent unpaid by the officer. In connection with these agreements, in December 1998 the Company loaned four officers a total of $5,795,000 to reduce their margin debt. An additional $1,530,000 was loaned during 1999, including a new loan to a fifth officer. The loans are full recourse and due in December 2003, with an interest rate equal to the Company's bank debt rate. At each balance sheet date, the loans are reviewed to determine whether a reserve for collectibility should be booked as compensation expense. To date, no reserve for collectibility has been recorded. As of March 2001, officer margin debt balances related to Company common stock were fully repaid, and the margin support agreements were terminated because they were no longer needed. Other Transactions A company, partially owned by a director of the Company, performs consulting services in connection with the Company's acquisition and divestiture programs, for which it received fees totaling $994,000 in 2000. The director- related company also represented the purchaser of properties sold by the Company during 1999 and invested in the purchase. The same director-related company performed consulting services in 1998 in connection with the Cook Inlet Acquisition. After the Company recovers its acquisition costs, including interest and subsequent property development and operating costs, the director-related company will receive, at its election, either a 20% working interest or a 1% overriding royalty interest conveyed from the Company's 100% working interest in these properties. 40 4. Debt The Company's outstanding debt consists of the following:
(in thousands) December 31 ------------------ 2000 1999 -------- ------- Long-term Debt: Senior debt- Bank debt under revolving credit agreements due May 12, 2005, 8.3% at December 31, 2000..................................... $469,000 $439,000 Subordinated debt- 9 1/4% senior subordinated notes due April 1, 2007.............. 125,000 125,000 8 3/4% senior subordinated notes due November 1, 2009........... 175,000 175,000 Spring Holding Company- Senior bank debt, 8.5%.......................................... - 116,100 Senior subordinated debt, 12.9%................................. - 7,000 Summer Acquisition Company- Senior bank debt, 8.5%.......................................... - 129,000 ----------- -------- Total long-term debt.............................................. $769,000 $991,100 =========== ========
Senior Debt In May 2000, the Company entered a new revolving credit agreement with commercial banks with a commitment of $800 million. Proceeds of this loan agreement were used to refinance the Company's previous senior credit facility and to fully repay a $25 million term loan and the separate bank debt of the Company's subsidiaries, Spring Holding Company and Summer Acquisition Company. In June 2000, the loan agreement was amended to allow the Company to issue letters of credit. Any letters of credit outstanding reduce the borrowing capacity under the revolving credit facility. As of December 31, 2000, letters of credit outstanding totaled $33 million. Borrowings at December 31, 2000 under the loan agreement were $469 million with unused borrowing capacity of $298 million. The borrowing base is redetermined annually based on the value and expected cash flow of the Company's proved oil and gas reserves. If borrowings exceed the redetermined borrowing base, the banks may require that the excess be repaid within a year. Based on reserve values at December 31, 2000 and parameters specified by the banks, the borrowing base supports borrowings in excess of the $800 million commitment. Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at any time without penalty. The Company periodically renegotiates the loan agreement to increase the borrowing commitment and extend the revolving facility. In February 2001, the loan agreement was amended to allow the repurchase of the Company's subordinated debt and to increase commodity hedging limits. On January 3, 2001, the Company purchased primarily gas-producing properties in East Texas and Louisiana for $115 million, of which $11.6 million had been paid in 2000. This acquisition was funded through borrowings under the loan agreement. The credit facility is secured by the Company's producing properties. Restrictions set forth in the loan agreement include limitations on the incurrence of additional indebtedness, the creation of certain liens, and the redemption or prepayment of subordinated indebtedness. The loan agreement also limits dividends to 25% of cash flow from operations, as defined, for the latest four consecutive quarterly periods. The Company is also required to maintain a current ratio of not less than one (where unused borrowing commitments are included as a current asset). The loan agreement provides the option of borrowing at floating interest rates based on the prime rate or at fixed rates for periods of up to six months based on certificate of deposit rates or London Interbank Offered Rates ("LIBOR"). Borrowings under the loan agreement at December 31, 2000 were based on LIBOR rates with maturity of one to six months and accrued at the applicable LIBOR rate plus 1 1/2%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. The Company also incurs a commitment fee on unused borrowing 41 commitments which was 0.35% at December 31, 2000. The weighted average interest rate on senior debt was 8.2% during 2000, 6.7% during 1999 and 6.9% during 1998. Subordinated Debt The Company sold $125 million of 9 1/4% senior subordinated notes on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes on October 28, 1997. The notes are general unsecured indebtedness that is subordinate to bank borrowings under the loan agreement. Net proceeds of $121.1 million from the 9 1/4% notes and $169.9 million from the 8 3/4% notes were used to reduce bank borrowings under the loan agreement. The 9 1/4% notes mature on April 1, 2007 and interest is payable each April 1 and October 1, while the 8 3/4% notes mature on November 1, 2009 with interest payable each May 1 and November 1. The Company has the option to redeem the 9 1/4% notes on April 1, 2002 and the 8 3/4% notes on November 1, 2002 at a price of approximately 105%, and thereafter at prices declining ratably at each anniversary to 100% in 2005. Upon a change in control of the Company, the noteholders have the right to require the Company to purchase all or a portion of their notes at 101% plus accrued interest. The notes were issued under indentures that place certain restrictions on the Company, including limitations on additional indebtedness, liens, dividend payments, treasury stock purchases, disposition of proceeds from asset sales, transfers of assets and transactions with subsidiaries and affiliates. See Note 7 regarding interest rate swap agreements. 5. Income Tax The effective income tax rate for the Company was different than the statutory federal income tax rate for the following reasons:
(in thousands) 2000 1999 1998 ------- ------- -------- Income tax expense (benefit) at the federal statutory rate of 34%............................. $59,987 $24,006 $(35,893) State and local taxes and other............................. (607) (41) 42 ------- ------- -------- Income tax expense (benefit)................................ $59,380 $23,965 $(35,851) ======= ======= ========
Components of income tax expense (benefit) are as follows:
(in thousands) 2000 1999 1998 ------- ------- -------- Current income tax.......................................... $ 387 $ 308 $ (107) Deferred income tax expense (benefit)....................... 63,792 28,697 (2,626) Net operating loss carryforward............................. (4,799) (5,040) (33,118) ------- ------- -------- Income tax expense (benefit)................................ $59,380 $23,965 $(35,851) ======= ======= ========
42 Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. The Company's net deferred tax liabilities are recorded as a current asset of $17,098,000 and a long-term liability of $82,476,000 at December 31, 2000, and a current asset of $4,168,000 and a long-term liability of $25,975,000 at December 31, 1999. Significant components of net deferred tax assets and liabilities are:
(in thousands) December 31 --------------------- 2000 1999 -------- -------- Deferred tax assets: Net operating loss carryforwards..................................... $ 69,370 $ 64,118 Accrued stock appreciation right and performance share compensation.. 916 985 Unrealized loss on trading securities................................ - 6,103 Derivative fair value loss........................................... 15,024 - Other................................................................ 5,038 2,891 -------- -------- Total deferred tax assets..................................... 90,348 74,097 -------- -------- Deferred tax liabilities: Property and equipment............................................... 148,363 92,115 Other................................................................ 7,363 3,789 -------- -------- Total deferred tax liabilities................................ 155,726 95,904 -------- -------- Net deferred tax assets (liabilities).................................. $(65,378) $(21,807) ======== ========
As of December 31, 2000, the Company has estimated tax loss carryforwards of approximately $210 million, of which $11 million are related to capital losses. The capital loss tax carryforwards expire in 2005 while the remaining $199 million are scheduled to expire in 2008 through 2020. Approximately $21.7 million of the tax loss carryforwards are the result of the Spring Acquisition. The Company has not booked any valuation allowance because it believes it has tax planning strategies available to realize its tax loss carryforwards. 6. Commitments and Contingencies Leases The Company leases offices, vehicles and certain other equipment in its primary locations under noncancelable operating leases. As of December 31, 2000, minimum future lease payments for all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows:
(in thousands) 2001................................. $12,147 2002................................. 11,937 2003................................. 11,604 2004................................. 7,005 2005................................. 5,051 Remaining............................ 21,357 ------- Total................................ $69,101 =======
Amounts incurred by the Company under operating leases (including renewable monthly leases) were $17,329,000 in 2000, $14,093,000 in 1999 and $11,180,000 in 1998. In March 1996, the Company sold its Tyrone gas processing plant and related gathering system for $28 million and entered an agreement to lease the facility from the buyers for an initial term of eight years at annual rentals of $4 million, and with fixed renewal options for an additional 13 years. This transaction was recorded as a sale and operating leaseback, with no gain or loss on the sale. 43 In November 1996, the Company sold its gathering system in Major County, Oklahoma for $8 million and entered an agreement to lease the facility from the buyers for an initial term of eight years, with fixed renewal options for an additional 10 years. Rentals are adjusted monthly based on the 30-day LIBOR rate and may be irrevocably fixed by the Company with 20 days advance notice. As of December 31, 2000, annual rentals were $1.7 million. This transaction was recorded as a sale and operating leaseback, with a deferred gain of $3.4 million on the sale. The deferred gain is amortized over the lease term based on pro rata rentals and is recorded in other long-term liabilities in the accompanying consolidated balance sheets. The deferred gain balance at December 31, 2000 was $2 million. Under each of the above sale and leaseback transactions, the Company does not have the right or option to purchase, nor does the lessor have the obligation to sell the facility at any time. However, if the lessor decides to sell the facility at the end of the initial term or any renewal period, the lessor must first offer to sell it to the Company at its fair market value. Additionally, the Company has a right of first refusal of any third party offers to buy the facility after the initial term. Letters of Credit The Company issued letters of credit totaling $33 million to counterparties and purchasers under certain hedge derivatives and physical delivery contracts. (Note 8). Employment Agreements Two executive officers have year-to-year employment agreements with the Company. The agreements are automatically renewed each year-end unless terminated by either party upon thirty days notice prior to each December 31. Under these agreements, the officers receive a minimum annual salary of $625,000 and $450,000, respectively, and are entitled to participate in any incentive compensation programs administered by the Board of Directors. The agreements also provide that, in the event the officer terminates his employment for good reason, as defined in the agreement, the Company terminates the employee without cause or a change in control of the Company occurs, the officer is entitled to a lump-sum payment of three times the officer's most recent annual compensation. Commodity Commitments The Company has entered into natural gas physical delivery contracts, futures contracts and swap agreements that effectively fix prices, and natural gas call options that provide ceiling prices. See Note 8. Litigation On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against the Company in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which the Company has assumed the obligation to pay royalties. The plaintiffs allege that the Company has reduced royalty payments by post-production deductions and has entered into contracts with subsidiaries that were not arm's-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by the Company in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. The Company contends that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm's-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. The Company further contends that any such fees enhance the value of the gas or the products derived from the gas. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. A hearing on the class certification issue has not been scheduled. Management believes it has strong defenses against this claim and intends to vigorously defend the action. Management's estimate of the potential liability from this claim has been accrued in the Company's financial statements. On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against the Company and certain of its subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False 44 Claims Act. The plaintiff alleges that the Company underpaid royalties on gas produced from federal leases and lands owned by Native Americans by at least 20% during the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for the Company to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against the Company and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. The Company and other defendants filed a motion to dismiss which has been heard by the Court and a decision is pending. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim is not currently determinable and no provision has been accrued in the Company's financial statements. A third lawsuit, Bishop, et al. v. Amoco Production Co., et al., was filed in May 2000 in the Third Judicial District Court in Lincoln County, Wyoming by owners of royalty and overriding royalty interests in wells located in Wyoming. The plaintiffs alleged that the Company and the other producer defendants deducted impermissible costs of production from royalty payments that were made to the plaintiffs and other similarly situated persons and failed to properly inform the plaintiffs and others of the deductions taken as allegedly required by Wyoming statutes. The action was brought as a class action on behalf of all persons who own an interest in wells located in Wyoming as to which the defendants pay royalties and overriding royalties. The plaintiffs sought a declaratory judgment that the deductions made were impermissible and sought damages in the amount of the deductions made, together with interest and attorneys' fees. The Company has reached a settlement of this action, which is subject to court approval. The Company has agreed to pay a total settlement amount of $572,000 for a release of claims relating to deductions taken by the Company, the statutory reporting of claims, and other miscellaneous matters. The Company further agreed that it would not take similar deductions from royalty owners in the future and to itemize other deductions from future royalty disbursements. The Company expects that the court will approve the settlement in April 2001. This settlement was accrued in the Company's financial statements. In February 2000, the Department of Interior notified the Company and several other producers that certain Native American leases located in the San Juan Basin have expired due to the failure of the leases to produce in paying quantities. The Department of Interior has demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. The Company has filed a Notice of Appeal with the Interior Board of Indian Appeals. The potential loss from these claims is currently not determinable, but could be material to the Company's annual earnings. The Company believes that the claim is without merit and that there is currently not a probable loss. No related provision is accrued in the Company's financial statements. The Company is involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on the Company's financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year. Other To date, the Company's expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, developments such as new regulations, enforcement policies or claims for damages could result in significant future costs. See also Note 3. 45 7. Financial Instruments The Company uses financial and commodity-based derivative contracts to manage exposures to commodity price and interest rate fluctuations. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. Commodity Price Hedging Instruments The Company periodically enters into futures contracts, energy swaps, collars and basis swaps to hedge its exposure to price fluctuations on crude oil and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts, the Company pays this excess to the counterparty and records an opportunity loss in the period related production occurs. When actual commodity prices are below the contractually provided fixed price, the Company receives this difference and records a gain in the production period. These gains and losses are recorded as a component of oil and gas revenues. See Note 8. In 2000, the Company recognized net losses on futures contracts and basis swap transactions of $40.5 million related to gas hedging and $7.8 million related to oil hedging. During 1999, the Company recognized net losses on futures contracts and basis swap transactions of $5.7 million related to gas hedging and $2.2 million related to oil hedging. During 1998, the Company recognized net gains of $7.7 million related to gas hedging. The Company occasionally sells gas call options. Because these options are covered by Company production and the strike prices are below current market gas prices, they have the same effect on the Company as product hedges. However, because written options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectively provided by the call options, has been recognized as a loss in derivative fair value, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged production occurs. For the year ended December 31, 2000, a derivative fair value loss of $55.8 million was recorded in the consolidated income statements, of which $1.3 million was cash settled. Interest Rate Swap Agreements In September 1998, to reduce variable interest rate exposure on debt, the Company entered into a series of interest rate swap agreements, effectively fixing its interest rate at an average of 6.9% on a total notional balance of $150 million until September 2005. In 1999 and 2000, the Company terminated these interest rate swaps, resulting in total proceeds received and a gain of $2 million. This gain has been deferred and is being amortized against interest expense through September 2005. To reduce the interest rate on a portion of its subordinated debt, the Company entered an agreement with a bank that has purchased on the market the Company's subordinated notes with a face value of $21.6 million. The Company pays the bank a variable interest rate based on three-month LIBOR rates, and receives semiannually from the bank the fixed interest rate on the notes. The term of the agreement for approximately half the notes is through April 2002, and for the remaining half is through November 2002. Any depreciation in market value of the notes from the date purchased by the bank is immediately payable to the bank. Any appreciation in the market value, including any depreciation payments, is receivable from the bank to the extent of the market value of the notes at the end of the agreement. The Company has the option of terminating this agreement and repurchasing the notes from the bank at any time at market value. 46 Fair Value Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2000 and 1999. The following are estimated fair values and carrying values of the Company's other financial instruments at each of these dates:
Asset (Liability) -------------------------------------------------- December 31, 2000 December 31, 1999 --------------------- ----------------------- Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value ---------- --------- --------- ---------- Investment in equity securities.. $ - $ - $ 29,052 $ 29,052 Long-term debt................... (769,000) (774,000) (991,100) (981,540) Futures contracts................ - (112,807) - (2,676) Basis swap agreements............ - 3,868 - (1,113) Call options..................... (53,769) (53,769) (347) (347) Interest rate swap agreements.... 473 2,651 218 2,503
The fair value of short-term borrowings and bank borrowings approximates the carrying value because of short-term interest rate maturities. The fair value of subordinated long-term debt is based on current market quotes. The fair value of futures contracts, swap agreements and call options is estimated based on current commodity prices and interest rates. Concentrations of Credit Risk Although the Company's cash equivalents and derivative financial instruments are exposed to the risk of credit loss, the Company does not believe such risk to be significant. Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of the Company's receivables are from a broad and diverse group of energy companies and, accordingly, do not represent a significant credit risk. The Company's gas marketing activities generate receivables from customers including pipeline companies, local distribution companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. The Company recorded an allowance for collectibility of all accounts receivable of $3,121,000 at December 31, 2000 and $2,150,000 at December 31, 1999. The Company's bad debt provision was $1,093,000 in 2000, $1,347,000 in 1999 and $411,000 in 1998. Financial and commodity-based swap contracts expose the Company to the credit risk of non-performance by the counterparty to the contracts. The Company does not believe this risk is significant since the exposure is diversified among major banks and financial institutions with high credit ratings. New Derivative Accounting Principle Effective January 1, 2001, the Company has adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the income statement. Change in fair value of effective cash flow hedges are recorded as a component of other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. Physical delivery contracts which cannot be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives. However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative (Note 8). The Company accounted for adoption of SFAS No. 133 on January 1, 2001 by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in accounting principle and an unrealized loss of $67.3 million in other comprehensive income. The charge to the income statement is primarily related to the Company's physical delivery contract to sell 35,500 Mcf of natural gas per day from 2002 through July 2005 at crude oil- based prices. The unrealized loss is related to the derivative fair value of cash flow hedges. Amounts recorded on the balance sheet at January 1, 2001 were a $103.6 million current liability, a $2.2 million long-term asset and a $70.8 million long-term liability related to the fair value of derivatives and a current deferred tax asset of $36.3 million and a reduction to the long-term tax liability of $24 million for the related tax benefits. 47 8. Natural Gas Sales Commitments The Company has entered into natural gas futures contracts and swap agreements that effectively fix prices, and natural gas call options that provide ceiling prices, for the production and periods shown below. The Company does not have any outstanding basis swap agreements as of March 2001. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.
Futures Contracts and Swap Agreements Call Options (a) --------------------------------- --------------------------------- Production Period Mcf per Day per Mcf Mcf per Day per Mcf ----------------------- ----------------- -------------- ----------------- -------------- 2001 April to September 80,000 $ 2.79 53,333 $2.60 - 3.05 October 80,000 2.79 53,333 2.60 - 3.05 November 80,000 2.86 20,000 2.95 December 80,000 2.93 20,000 2.95 2002 January to March 10,000 5.47 - - -------------------------------------
(a) Includes a natural gas call option to sell 20,000 Mcf per day in the San Juan Basin at an average ceiling index price of $2.70 per Mcf for the year 2001 which is exercisable in December 2001. Based on current San Juan Basin basis of approximately $0.30 per Mcf for April through October and $0.20 for November and December, and including premium received of $0.05 per Mcf, this call option is reflected above at a NYMEX prices of $3.05 and $2.95 per Mcf. The Company's settlement of futures contracts and swap agreements related to first quarter 2001 gas production resulted in a net loss of approximately $26 million. This loss will be recognized as a decrease in gas revenue of approximately $0.78 per Mcf in the first quarter of 2001. The Company has entered into physical delivery contracts which cannot be net cash settled and are therefore considered to be normal sales. These contracts effectively fix prices for the following production and periods:
Location Production Period Mcf per Day Fixed Price per Mcf -------------------- ----------------------------- ----------- -------------------- East Texas April 2001 to March 2002 40,000 $5.42 Arkoma April to September 2001 90,000 5.55 October 2001 to March 2002 50,000 5.36 San Juan Basin April to September 2001 25,000 5.14 October 2001 to March 2002 10,000 5.05 Rocky Mountains April 2001 to March 2002 10,000 4.97 Mid-Continent April to September 2001 45,000 5.45 October 2001 to March 2002 30,000 5.55
Other Physical Delivery Contracts From August 1995 through July 1998 the Company received an additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, the Company agreed to sell 11,650 Mcf per day from August 1998 through May 2000 at the index price and 21,650 Mcf per day from June 2000 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. After contract amendments in May and October 2000, the Company has agreed to sell 21,650 Mcf per day at the index price through December 2000, 34,344 Mcf per day at the index price in 2001 and 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract is priced based on crude oil, which is not clearly and closely associated with natural gas prices, it must be accounted for as a derivative financial instrument under SFAS No. 133 beginning January 1, 2001 (Note 7). 48 As partial consideration for an acquisition, the Company agreed to sell gas volumes ranging from 40,000 Mcf in 2000 to 35,000 Mcf in 2003 at specified discounts from index prices. This commitment was recorded at its total value of $7.5 million in March 1999 in other current and long-term liabilities. The discounts are charged to the liability as taken. As of December 31, 2000, $1.6 million is recorded in other current liabilities and $2.4 million is recorded in other long-term liabilities related to this commitment. The Company has committed to sell all gas production from certain East Texas properties to EEX Corporation at market prices through the earlier of December 31, 2001, or until a total of approximately 34.3 billion cubic feet (27.8 billion cubic feet net to the Company's interest) of gas has been delivered. Based on current production, this sales commitment is approximately 24,700 Mcf (20,000 Mcf net to the Company's interest) per day. As a part of the Ocean Energy Acquisition, the Company assumed a commitment to sell 6,800 Mcf of gas per day through April 2003 at prices which are adjusted by the monthly index price. In 2000, the prices ranged from $0.50 to $0.95 per Mcf. Delivery of the committed sales volumes is in Arkansas. 9. Equity Three-for-Two Stock Splits The Company effected three-for-two common stock splits on February 25, 1998 and September 18, 2000. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits. Common Stock The following reflects the Company's common stock activity:
Shares Issued Shares in Treasury ----------------------- ------------------------ Year Ended December 31, Year Ended December 31, ----------------------- ------------------------ (in thousands) 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------- ------- ------ Balance, beginning of year.............. 87,283 81,072 69,466 13,949 13,981 10,291 Issuance/sale of common stock........... - 6,000 10,805 (6,600) (3,000) (2,883) Issuance/vesting of performance shares.. 813 195 123 381 - 41 Stock option exercises.................. 3,195 16 678 276 77 37 Treasury stock purchases................ - - - 5,891 2,891 6,495 Cancellation of shares.................. (8,866) - - (8,866) - - Preferred stock converted to common..... 162 - - - - - ------ ------ ------ ------ ------ ------ Balance, end of year.................... 82,587 87,283 81,072 5,031 13,949 13,981 ====== ====== ====== ====== ====== ======
In April 1998, the Company completed a public offering of 11.3 million shares of common stock, of which 10.8 million shares were sold by the Company and the remaining shares were sold by a stockholder. The Company's net proceeds from the offering of $133.1 million were used to partially repay bank debt used to fund the East Texas Basin Acquisition. The offering was made pursuant to the shelf registration statement filed with the Securities and Exchange Commission in February 1998. See "Shelf Registration Statement" below. In September 1998, the Company issued from treasury 2.9 million shares to affiliates of Shell Oil Company for the Cook Inlet Acquisition. The Company effectively guaranteed Shell a $13.33 per share value. As of December 31, 1998, these shares were valued at $13.33 per share, or a total of $38.4 million. The $13.33 guarantee was effectively settled in July 1999 upon the Company's repurchase of these shares from Shell at $8.83 per share, or $25.5 million, and net additional payments to Shell of $13 million which was charged to equity at that date. 49 In July 1999, the Company issued 6 million shares of common stock at its fair value of $7.617 per share in exchange for its 50% interest in Spring Holding Company and for cash proceeds of $3.2 million which were used to reduce bank debt (Note 14). Also in July 1999, the Company sold from treasury 3 million shares of common stock in an underwritten public offering for net proceeds of approximately $26.5 million. The proceeds were used to repurchase the 2.9 million shares of common stock issued to Shell for the Cook Inlet Acquisition. The offering was made pursuant to the shelf registration statement. In May 2000, in conjunction with the dissolution of Whitewine Holding Company, the Company's wholly owned subsidiary, 8.9 million shares were canceled from treasury stock. This transaction caused a $71.5 million reduction in treasury stock with an offsetting reduction in additional paid-in capital, resulting in no change to total stockholders' equity. In November 2000, the Company sold from treasury 6.6 million shares of common stock in an underwritten public offering for net proceeds of approximately $126.1 million. The proceeds were used to reduce outstanding indebtedness. The offering was made pursuant to the shelf registration statement. Performance Shares The Company issued performance shares totaling 820,000 in 2000, 213,000 in 1999 and 123,000 in 1998 (Note 12). In October 1999, 18,000 performance shares were forfeited from the shares issued in 1998. Treasury Stock The Company's open market treasury share acquisitions totaled 5.3 million shares in 2000 at an average price of $7.88, 7,500 shares in 1999 at an average price of $7.04 and 6.5 million shares in 1998 at an average price of $10.10 per share. Through March 26, 2001, 4.3 million shares remain under the May 2000 Board of Directors' authorization to repurchase 4.5 million shares of the Company's common stock. Stockholder Rights Plan In August 1998, the Board of Directors adopted a stockholder rights plan that is designed to assure that all stockholders receive fair and equal treatment in the event of any proposed takeover of the Company. Under this plan, a dividend of one preferred share purchase right was declared for each outstanding share of common stock, par value $.01 per share, payable on September 15, 1998 to stockholders of record on that date. Each right entitles stockholders to buy one one-thousandth of a share of newly created Series A Junior Participating Preferred Stock at an exercise price of $80, subject to adjustment in the event a person acquires or makes a tender or exchange offer for 15% or more of the outstanding common stock. In such event, each right entitles the holder (other than the person acquiring 15% or more of the outstanding common stock) to purchase shares of common stock with a market value of twice the right's exercise price. At any time prior to such event, the Board of Directors may redeem the rights at one cent per right. The rights can be transferred only with common stock and expire in ten years. Shelf Registration Statement In February 1998, the Company filed a shelf registration statement with the Commission to potentially offer securities which could include debt securities, preferred stock, common stock or warrants to purchase debt securities, preferred stock or common stock. The shelf registration statement was amended in April 1998 to increase the maximum total price of securities to be offered to $400 million, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities are to be used for general corporate purposes, including reduction of bank debt. After the April 1998, July 1999 and November 2000 common stock offerings, $99.4 million remains available under the shelf registration statement for future sales of securities. 50 Common Stock Warrants As partial consideration for producing properties acquired in December 1997, the Company issued warrants to purchase 1,427,701 shares of common stock at a price of $10.05 per share for a period of five years. These warrants were valued at $5.7 million and recorded as additional paid-in capital. Common Stock Dividends The Board of Directors declared quarterly dividends of $0.0267 per common share in 1998, $0.0067 per common share from 1999 through second quarter 2000 and $0.01 per common share for the third and fourth quarters of 2000. See Note 4 regarding restrictions on dividends. Series A Convertible Preferred Stock Series A convertible preferred stock is recorded in the accompanying consolidated balance sheets at its liquidation preference of $25 per share. Cumulative dividends on preferred stock are payable quarterly in arrears, when declared by the Board of Directors, based on an annual rate of $1.5625 per share. The preferred stock has no stated maturity and no sinking fund, and is redeemable, in whole or in part, by the Company. The preferred stock is convertible at the option of the holder at any time, unless previously redeemed, into shares of common stock at a rate of 3.24 shares of common stock for each share of preferred stock, subject to adjustment in certain events. During 2000, 50,000 shares of convertible preferred stock were converted into 162,000 shares of common stock. In January 2001, the Company sent notice to preferred stockholders that it would redeem all outstanding shares on February 16, 2001 at a price of $25.94 per share plus accrued and unpaid dividends. Prior to the redemption date, 1.1 million outstanding shares of preferred stock were converted into 3.5 million common shares in 2001. 10. Earnings Per Share The following reconciles earnings (numerator) and shares (denominator) used in the computation of basic and diluted earnings per share:
(in thousands, except per share data) Earnings Earnings Shares per Share --------- --------- ----------- 2000 ------------------------------------------------ Basic Net income.................................... $116,993 Preferred stock dividends..................... (1,758) -------- Earnings available to common stock - basic.... 115,235 71,154 $ 1.62 ========== Diluted Effect of dilutive securities: Stock options................................ - 518 Preferred stock.............................. 1,758 3,647 Warrants..................................... - 387 -------- ------ Earnings available to common stock - diluted.. $116,993 75,706 $ 1.55 ======== ====== ==========
1999 ------------------------------------------------ Basic Net income.................................... $ 46,743 Preferred stock dividends..................... (1,779) -------- Earnings available to common stock - basic.... 44,964 70,228 $ 0.64 ========== Diluted Effect of dilutive securities: Stock options................................ - 161 Preferred stock.............................. 1,779 3,690 Warrants..................................... - - -------- ------ Earnings available to common stock - diluted.. $ 46,743 74,079 $ 0.63 ======== ====== ==========
51
(in thousands, except per share data) Earnings Earnings Shares per Share ---------- -------- --------- 1998 ------------------------------------------------ Basic Net loss...................................... $(69,719) Preferred stock dividends..................... (1,779) -------- Loss available to common stock - basic........ (71,498) 65,094 $(1.10) ========== Diluted Effect of dilutive securities: Stock options................................ - 507 Warrants..................................... - 35 -------- ------ Loss available to common stock - diluted...... $(71,498) 65,636 $(1.10) (a) ======== ====== ==========
(a) Because of the antidilutive effect of dilutive securities on loss per common share, diluted loss available to common stock is the same as basic. 11. Supplemental Cash Flow Information The consolidated statements of cash flows exclude the following non-cash transactions (Notes 9, 12 and 13): - Cancellation of 8.9 million shares of treasury stock in 2000 - Conversion of 50,000 shares of preferred stock to common stock in 2000 - Sale of Hugoton Royalty Trust units in 2000 in exchange for 495,000 shares of common stock valued at $11.3 million, and in 1999 in exchange for 74,000 shares of common stock valued at $700,000 - Purchase of a 50% interest in Spring Holding Company in 1999 in exchange for 5.6 million shares of common stock, valued at $42.5 million - The Cook Inlet Acquisition in 1998, a purchase of oil-producing properties for 2.9 million shares of common stock, a related effective guarantee of $13.33 per share value and a $6 million note payable - Performance shares activity, including: - Grants of 820,000 shares in 2000, 213,000 shares in 1999 and 123,000 shares in 1998 to key employees and nonemployee directors - Vesting of 1,007,000 shares in 2000, 18,000 shares in 1999 and 137,000 shares in 1998 - Forfeiture of 18,000 shares in 1999 - Receipt of common stock of 44,000 shares (valued at $967,000) in 2000 and 13,000 shares (valued at $181,000) in 1998 for the option price of exercised stock options Interest payments in 2000 totaled $80,067,000 (including $3,488,000 of capitalized interest), $70,500,000 in 1999 (including $1,353,000 of capitalized interest) and $57,200,000 in 1998 (including $1,070,000 of capitalized interest). Income tax payments were $1,085,000 in 2000; net income tax refunds were $322,000 during 1999 and $454,000 during 1998. 52 12. Employee Benefit Plans 401(k) Plan The Company sponsors a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. The Company matches employee contributions of up to 10% of wages (8% of wages prior to January 1, 1998). Employee contributions vest immediately while the Company's matching contributions vest 100% upon the earlier of three consecutive years of participation in the plan or five years of service. All employees over 21 years of age may participate. Company contributions under the plan were $3,226,000 in 2000, $2,514,000 in 1999 and $1,766,000 in 1998. Post-Retirement Health Plan Effective January 1, 2001, the Company adopted a retiree medical plan for employees who retire at age 55 or over with a minimum of five years full-time service. Benefits under the plan are the same as for active employees, and continue until the retired employee or the employee's dependents are eligible for Medicare or another similar federal health insurance program. After Medicare eligibility, only prescription coverage is provided. Premiums are only charged to dependents. Post-retirement medical benefits are not pre-funded by the Company, but are paid when incurred. As of the plan's inception, total prior service cost is estimated to be $804,000. For the year 2001, total expense is estimated to be $1.1 million which includes the total prior service cost, current year service cost and interest. The annual rate of increase in health care costs were assumed to range from 9% in 2000 to 6% in 2006 and beyond. An increase of 1% in the assumed health care cost trend rate would result in an increase in the total estimated service and interest cost of $158,000 for 2001, and would increase the estimated prior service cost at January 1, 2001 by $417,000. The weighted average discount rate used to determine the prior service cost and interest was 7.75% at January 1, 2001. 1994 and 1997 Stock Incentive Plans Under the 1994 Stock Incentive Plan and the 1997 Stock Incentive Plan, a total of 3,375,000 shares of common stock may be issued under each plan to directors, officers and other key employees pursuant to grants of stock options or performance shares of common stock. At December 31, 2000, there are 49,000 shares available for grant under the 1994 Plan and 649,000 shares available for grant under the 1997 Plan. Options vest and become exercisable on terms specified when granted by the compensation committee ("the Committee") of the Board of Directors. Options granted under the 1994 Plan have a term of ten years and are not exercisable until six months after their grant date. Options granted under the 1994 Plan and the 1997 Plan generally vest in equal amounts over five years, with provisions for earlier vesting if specified performance requirements are met. In May 1998, all options under the 1994 Plan vested by resolution of the Board of Directors. 1998 Stock Incentive Plan In May 1998, the stockholders approved the 1998 Stock Incentive Plan under which 9,000,000 shares of common stock are available for grant. Grants under the 1998 Plan are subject to the provision that outstanding stock options and performance shares under all the Company's stock incentive plans cannot exceed 6% of the Company's outstanding common stock at the time such grants are made. At December 31, 2000, there were 1,759,000 shares available for grant under the 1998 Plan. Stock options generally vest and become exercisable annually in equal amounts over a five-year period, with provision for accelerated vesting when the common stock price reaches specified levels. There were 1,135,000 options outstanding at December 31, 2000 that vested when the common stock price closed above $30.00 on March 9, 2001 and 104,000 options that vest when the common stock price closes above $32.50. In 2001, an additional 927,000 options were granted, of which 647,000 have vested and 280,000 vest when the stock price closes above $32.50. Performance Shares Performance shares granted under the 1994, 1997 and 1998 Plans are subject to restrictions determined by the Committee and are subject to forfeiture if performance targets are not met. Otherwise, holders of performance shares generally have all the voting, dividend and other rights of other stockholders. The Company issued performance shares to key employees totaling 820,000 in 2000, 195,000 in 1999 and 108,000 in 1998. Performance shares vested, totaling 53 1,007,000 in 2000 and 122,000 in 1998, when the common stock price reached specified levels. In 1999, 18,000 performance shares issued in 1998 were forfeited. General and administrative expense includes compensation related to these performance share grants of $18.4 million in 2000, $102,000 in 1999 and $1.6 million in 1998. As of December 31, 2000, there were 85,000 performance shares that vested when the common stock price closed above $30.00 on March 9, 2001 and 13,500 performance shares that vest in increments of 4,500 in each of 2001, 2002 and 2003. In March 2001, an additional 77,000 performance shares were issued that vest when the stock price closes above $32.50. The Company also issued to nonemployee directors a total of 18,000 performance shares in 1999 and 15,000 performance shares in 1998, which vested upon grant. In February 2001, the Board approved an agreement with certain executive officers under which the officers, immediately prior to a change in control of the Company, will receive a total grant of 77,000 performance shares for every $2.50 increment in the closing price of the Company's common stock above $30.00. The number of performance shares granted under the agreement will be reduced by the number of performance shares awarded to the officers between the date of the agreement and the date of the change in control. Certain officers will also receive a total grant of 155,000 performance shares immediately prior to a change in control without regard to the price of the Company's common stock. Royalty Trust Option Plans Under the 1998 Royalty Trust Option Plan, the Company granted certain officers options to purchase 1,290,000 Hugoton Royalty Trust units at prices of $8.03 and $9.50 per unit, or a total of $12 million. These units were exercised in 1999 and 2000, resulting in non-cash compensation expense of $7.1 million in 2000 and $60,000 in 1999 (Note 13). Option Activity and Balances The following summarizes option activity and balances from 1998 through 2000:
Weighted Average Exercise Stock Price Options --------- ---------- 1998 ------------------------------------------------------- Beginning of year..................................... $ 7.41 3,530,170 Grants.............................................. 11.68 2,093,625 Exercises........................................... 7.76 (1,632,691) Forfeitures......................................... 11.46 (32,625) ---------- End of year........................................... 9.49 3,958,479 ========== Exercisable at end of year............................ 7.35 2,053,854 ========== 1999 ------------------------------------------------------- Beginning of year..................................... $ 9.49 3,958,479 Grants.............................................. 7.11 614,812 Exercises........................................... 4.57 (15,693) Forfeitures......................................... 7.75 (42,862) ---------- End of year........................................... 9.20 4,514,736 ========== Exercisable at end of year............................ 7.39 2,009,361 ========== 2000 --------------------------------------------------------- Beginning of year..................................... $ 9.20 4,514,736 Grants.............................................. 19.99 4,762,503 Exercises........................................... 9.81 (4,643,414) Forfeitures......................................... 8.91 (246,336) ---------- End of year........................................... 20.14 4,387,489 ========== Exercisable at end of year............................ 19.24 3,148,509 ==========
54 The following summarizes information about outstanding options at December 31, 2000:
Options Outstanding Options Exercisable ------------------------------ --------------------------- Weighted Weighted Weighted Average Average Average Range of Remaining Exercise Exercise Exercise Prices Number Term Price Number Price ------------------------ --------- --------- -------- ----------- ------------- $2.76 - $8.28 163,872 6.2 years $ 6.42 163,872 $ 6.42 $8.29 - $13.80 370,912 7.5 years 12.31 370,912 12.31 $13.81 - $19.32 332,425 7.6 years 14.29 332,425 14.29 $19.33 - $27.59 3,520,280 9.8 years 22.16 2,281,300 22.00 ---------- ----------- 4,387,489 3,148,509 ========== ===========
Estimated Fair Value of Grants Using the Black-Scholes option-pricing model and the following assumptions, the weighted average fair value of option grants was estimated to be $10.27 in 2000, $4.27 in 1999 and $4.55 in 1998.
2000 1999 1998 ---- ---- ---- Risk-free interest rates......... 5.8% 5.8% 5.6% Dividend yield................... 0.2% 3.0% 3.2% Weighted average expected lives.. 5 years 5 years 5 years Volatility....................... 53% 91% 52%
Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair Value The following are pro forma earnings (loss) available to common stock and earnings (loss) per common share for 2000, 1999 and 1998, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS 123, Accounting for Stock-Based Compensation:
(in thousands, except per share data) 2000 1999 1998 --------- -------- --------- Earnings (loss) available to common stock: As reported............................... $115,235 $ 44,964 $(71,498) Pro forma................................. $ 91,194 $ 40,373 $(75,785) Earnings (loss) per common share: Basic As reported..................... $ 1.62 $ 0.64 $ (1.10) Pro forma....................... $ 1.28 $ 0.57 $ (1.16) Diluted As reported..................... $ 1.55 $ 0.63 $ (1.10) Pro forma....................... $ 1.23 $ 0.57 $ (1.16)
13. Sale of Hugoton Royalty Trust Units In December 1998, the Company formed the Hugoton Royalty Trust by conveying 80% net profits interests in properties located in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. In April and May 1999, the Company sold 17 million, or 42.5%, of the trust units in an initial public offering at a price of $9.50 per unit, less underwriters' discount and expenses. Total net proceeds from the sale were $148.6 million, resulting in a gain of $40.3 million before income tax. Proceeds from the sale were used to reduce bank debt. 55 In 1999 and 2000, officers exercised options to purchase a total of 1.3 million Hugoton Royalty Trust units from the Company pursuant to the 1998 Royalty Trust Option Plan in exchange for shares of Company common stock. The Company recognized gains of $11 million in 2000 and $235,000 in 1999 on these sales of trust units. 14. Acquisitions and Dispositions Acquisitions On July 1, 1999, the Company and Lehman Brothers Holdings, Inc. acquired predominantly gas-producing properties in the Arkoma Basin through the purchase of the common stock of Spring Holding Company, a private oil and gas company located in Tulsa, Oklahoma for $85 million. The Company issued 5.6 million shares of common stock for its ownership interest in Spring and Lehman contributed $42.5 million in cash. The Company and Lehman each owned 50% of a limited liability company that acquired the common stock of Spring. Pursuant to a put and call agreement, the Company purchased Lehman's interest in September 1999 for $44.3 million, or $1.8 million in excess of the recorded minority interest, which excess was recorded as producing property cost. Property cost associated with the Spring acquisition totaled approximately $235 million, a portion of which was attributed to other than producing properties, including a gas gathering system, compressors, undeveloped leasehold cost and other tangible property. After purchase accounting adjustments, including a $14.1 million step- up adjustment for deferred income taxes, the cost of the properties was $257 million. Although the Company and Lehman had equal board representation and control of Spring, the Company's management controlled operations of the properties from July 1, 1999 and had the right to purchase Lehman's interest pursuant to the call agreement. The Company accordingly consolidated its investment in Spring from July 1, 1999, with recognition of Lehman's investment as a minority interest through September 1999. On September 15, 1999, the Company and Lehman acquired Arkoma Basin oil and gas properties from Ocean Energy, Inc. for $231 million. The original purchase price of $235.3 million was reduced by estimated net revenue received between the July 1, 1999 effective date and the closing date. The Company and Lehman each owned 50% of Whitewine Holding Company, which was formed to acquire the Arkoma Basin properties. Pursuant to a put and call agreement, the Company purchased Lehman's 50% interest in the Ocean Energy Acquisition on March 31, 2000 for $111 million, or $11 million in excess of the recorded minority interest, which excess was recorded as producing property cost. Although the Company and Lehman had equal board representation and control of Whitewine, the Company's management controlled operations of the properties from September 15, 1999 and had the right to purchase Lehman's interest pursuant to the call agreement. Whitewine's financial results are consolidated in the Company's financial statements, with recognition of Lehman's 50% interest as a minority interest through March 31, 2000. Dispositions On May 4, 1999, the Company sold nonoperated producing properties in the San Juan Basin of New Mexico to Vastar Resources, Inc. for $29.9 million. The Company sold other nonoperated producing properties in June 1999 for approximately $15 million. Proceeds from the sales were used to reduce bank debt. On September 14, 1999, producing properties were sold for approximately $63.5 million before closing costs in two transactions. The Company sold primarily nonoperated properties in Oklahoma, the Permian Basin of West Texas and New Mexico, the Panhandle area of Texas and the Green River Basin of Wyoming, including sales of $22.5 million of properties acquired in the Spring acquisition. In March 2000, the Company sold primarily gas-producing properties in Crockett County, Texas for gross proceeds of $43 million and sold oil- and gas- producing properties in Lea County, New Mexico for gross proceeds of $25.3 million. Acquisitions have been recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for the year ended December 31, 1999 as if these acquisitions and the sale of Hugoton Royalty Trust units and other properties had been consummated immediately prior to January 1, 1999. Pro forma results 56 are not presented for the year ended December 31, 2000 because the effects of these transactions excluded from 2000 results are not significant. These pro forma results are not necessarily indicative of future results.
(in thousands, except per share data) Pro Forma ----------- (Unaudited) Revenues............................ $353,186 ======== Net income.......................... $ 45,552 ======== Earnings available to common stock.. $ 43,924 ======== Earnings per common share: Basic......................... $ 0.60 ======== Diluted....................... $ 0.59 ========
On December 5, 2000, the Company entered into a definitive agreement to acquire primarily gas-producing properties in East Texas and Louisiana for $115 million from Herd Producing Company, Inc. The purchase was completed on January 3, 2001, and was funded through borrowings under existing bank lines. The purchase is subject to typical post-closing adjustments. On January 2, 2001, the Company repurchased 9,598,000 MMBtu of natural gas for $9.9 million from a production payment sold to EEX Corporation in a 1998 acquisition. In December 2001, the Company can repurchase an additional 9,598,000 MMBtu of gas from the production payment for approximately $11 million. 15. Quarterly Financial Data (Unaudited) The following are summarized quarterly financial data for the years ended December 31, 2000 and 1999:
Quarter ------------------------------------------ (in thousands, except per share data) 1st 2nd 3rd 4th --------- --------- --------- --------- 2000 --------------------------------------- Revenues.......................... $113,326 $ 121,650 $160,519 $205,356 Gross profit (a).................. $ 44,997 $ 30,094 $ 80,981 $105,490 Earnings available to common stock.................... $ 33,267 $ 798 $ 31,366 $ 49,804 Earnings per common share Basic........................... $ 0.46 $ 0.01 $ 0.45 $ 0.68 Diluted......................... $ 0.44 $ 0.01 $ 0.43 $ 0.64 Average shares outstanding........ 72,441 68,918 69,518 73,728 1999 --------------------------------------- Revenues.......................... $ 69,415 $ 65,550 $ 95,326 $111,004 Gross profit (a).................. $ 15,154 $ 13,601 $ 36,420 $ 44,318 Earnings (loss) available to common stock.................... $ (2,091) $ 28,341 $ 13,071 $ 5,643 Earnings (loss) per common share Basic........................... $ (0.03) $ 0.42 $ 0.18 $ 0.08 Diluted......................... $ (0.03) $ 0.41 $ 0.17 $ 0.08 Average shares outstanding........ 67,091 67,100 73,371 73,247
(a) Operating income before general and administrative expense. 57 16. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited) All of the Company's operations are directly related to oil and gas producing activities located in the United States. Costs Incurred Related to Oil and Gas Producing Activities The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes:
(in thousands) 2000 1999 1998 -------- -------- -------- Acquisitions: Producing properties................ $ 31,983 $505,912 $339,889 Undeveloped properties.............. 3,490 4,182 514 Development (a)........................ 163,224 89,306 69,367 Exploration: Geological and geophysical studies.. 829 872 7,943 Dry hole expense.................... - - - Rental expense and other............ 218 32 91 -------- -------- -------- Total.................................. $199,744 $600,304 $417,804 ======== ======== ========
(a) Includes capitalized interest of $3,488,000 in 2000, $1,353,000 in 1999 and $1,070,000 in 1998. Proved Reserves Independent petroleum engineers have estimated the Company's proved oil and gas reserves, all of which are located in the United States. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Standardized Measure The standardized measure of discounted future net cash flows ("standardized measure") and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits. 58 The standardized measure does not represent management's estimate of the Company's future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.
(in thousands) Oil Gas Natural Gas (Bbls) (Mcf) Liquids (Bbls) ------------ ------------ -------------- Proved Reserves December 31, 1997............................ 47,854 815,775 13,810 Revisions.................................. (5,893) (5,429) 2,631 Extensions, additions and discoveries...... 821 172,059 1,875 Production................................. (4,598) (83,847) (1,222) Purchases in place......................... 16,331 311,260 80 Sales in place............................. (5) (594) - ----------- ----------- ----------- December 31, 1998........................... 54,510 1,209,224 17,174 Revisions.................................. 10,792 60,011 1,838 Extensions, additions and discoveries...... 3,003 166,669 3,357 Production................................. (5,112) (105,120) (1,325) Purchases in place......................... 2,790 494,666 20 Sales in place............................. (4,380) (279,827) (3,162) ----------- ----------- ----------- December 31, 1999............................ 61,603 1,545,623 17,902 Revisions.................................. 2,709 142,974 3,709 Extensions, additions and discoveries...... 1,145 258,843 1,951 Production................................. (4,736) (125,857) (1,622) Purchases in place......................... 833 26,557 72 Sales in place............................. (3,109) (78,457) - ----------- ----------- ----------- December 31, 2000............................ 58,445 1,769,683 22,012 =========== =========== =========== Proved Developed Reserves December 31, 1997............................ 33,835 677,710 11,494 =========== =========== =========== December 31, 1998............................ 42,876 968,495 14,000 =========== =========== =========== December 31, 1999............................ 48,010 1,225,014 13,781 =========== =========== =========== December 31, 2000............................ 46,334 1,328,953 16,448 =========== =========== ===========
Standardized Measure of Discounted Future December 31 Net Cash Flows Relating to Proved Reserves ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- (in thousands) Future cash inflows.......................... $18,866,832 $ 5,113,094 $ 3,041,776 Future costs: Production................................. (3,237,574) (1,549,401) (1,135,789) Development................................ (389,698) (294,250) (228,561) ----------- ----------- ----------- Future net cash flows before income tax...... 15,239,560 3,269,443 1,677,426 Future income tax............................ (4,947,614) (718,892) (231,249) ----------- ----------- ----------- Future net cash flows........................ 10,291,946 2,550,551 1,446,177 10% annual discount.......................... (5,029,916) (1,153,611) (637,774) ----------- ----------- ----------- Standardized measure (a)..................... $ 5,262,030 $ 1,396,940 $ 808,403 =========== =========== ===========
(a) Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $7,748,632,000 in 2000, $1,765,936,000 in 1999 and $908,606,000 in 1998. 59 Changes in Standardized Measure of Discounted Future Net Cash Flows
(in thousands) 2000 1999 1998 ------------ ----------- ---------- Standardized measure, January 1........ $ 1,396,940 $ 808,403 $ 642,109 ----------- ---------- --------- Revisions: Prices and costs..................... 5,096,973 608,123 (184,568) Quantity estimates................... 190,457 62,033 65,600 Accretion of discount................ 123,225 70,256 58,195 Future development costs............. (196,048) (113,110) (104,636) Income tax........................... (2,082,745) (259,403) 53,758 Production rates and other........... 1,378 (137) (296) ----------- ---------- --------- Net revisions.................... 3,133,240 367,762 (111,947) Extensions, additions and discoveries.. 1,018,349 125,209 96,829 Production............................. (441,323) (215,869) (146,498) Development costs...................... 128,757 70,275 56,904 Purchases in place (a)................. 115,866 414,759 271,806 Sales in place (b)..................... (89,799) (173,599) (800) ----------- ---------- --------- Net change....................... 3,865,090 588,537 166,294 ----------- ---------- --------- Standardized measure, December 31...... $ 5,262,030 $1,396,940 $ 808,403 =========== ========== =========
(a) Generally based on the year-end present value (at year-end prices and costs) plus the cash flow received from such properties during the year, rather than the estimated present value at the date of acquisition. (b) Generally based on beginning of the year present value (at beginning of year prices and costs) less the cash flow received from such properties during the year, rather than the estimated present value at the date of sale. Price and cost revisions are primarily the net result of changes in year- end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity. Year-end realized oil prices used in the estimation of proved reserves and calculation of the standardized measure were $25.49 for 2000, $24.17 for 1999 and $9.50 for 1998. Year-end average realized gas prices were $9.55 for 2000, $2.20 for 1999 and $2.01 for 1998. Year-end average realized natural gas liquids prices were $26.33 for 2000, $13.83 for 1999 and $3.99 for 1998. Proved oil and gas reserves at December 31, 2000 include: - 1,970,000 Bbls of oil and 223,578,000 Mcf of gas and discounted present value before income tax of $842,346,000 related to the Company's ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2000. - 747,000 Bbls of oil and 7,986,000 Mcf of gas and discounted present value before income tax of $38,403,000 related to the Company's ownership of approximately 23% of Cross Timbers Royalty Trust units at December 31, 2000. Based on NYMEX prices of $25.00 per Bbl for oil and $5.00 per Mcf for gas (which are comparable to realized prices of $23.69 per Bbl for oil and $4.79 per Mcf for gas), and an $18.86 per Bbl realized price for natural gas liquids, estimated proved reserves at December 31, 2000 would be 57.7 million Bbls of oil, 1.75 Tcf of natural gas and 21.6 million Bbls of natural gas liquids. Using these prices, the present value of estimated future cash flows, discounted at 10% and before income tax, would be $3,834,024,000. 60 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Cross Timbers Oil Company We have audited the accompanying consolidated balance sheets of Cross Timbers Oil Company and its subsidiaries as of December 31, 2000 and 1999, and the related consolidated income statements, statements of cash flows and stockholders' equity for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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 the Company as of December 31, 2000 and 1999, and the results of its operations and its 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. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Fort Worth, Texas March 22, 2001 61 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, on the 2nd day of April 2001. CROSS TIMBERS OIL COMPANY By Bob R. Simpson --------------------------------------- Bob R. Simpson, Chairman of the Board and Chief Executive 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 indicated on the 2nd day of April 2001. PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS) DIRECTORS Bob R. Simpson J. Luther King, Jr. ---------------------------------------- ------------------------------------ Bob R. Simpson, Chairman of the Board J. Luther King, Jr. and Chief Executive Officer Steffen E. Palko Jack P. Randall ---------------------------------------- ------------------------------------ Steffen E. Palko, Vice Chairman of the Jack P. Randall Board and President Scott G. Sherman ------------------------------------ Scott G. Sherman Herbert D. Simons ------------------------------------ Herbert D. Simons PRINCIPAL FINANCIAL OFFICER PRINCIPAL ACCOUNTING OFFICER Louis G. Baldwin Bennie G. Kniffen ------------------------------------------ ------------------------------------ Louis G. Baldwin, Executive Vice President Bennie G. Kniffen, Senior Vice and Chief Financial Officer President and Controller 62 INDEX TO EXHIBITS Exhibit No. Description Page -------- ----------------------------------------------------------- ------ 3.1 Restated Certificate of Incorporation of Cross Timbers Oil Company, as restated on April 21, 1998 (incorporated by reference to Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2000) 3.2 Bylaws of Cross Timbers Oil Company (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-1, File No. 33-59820) 4.1 Indenture dated as of April 1, 1997, between Cross Timbers Oil Company and The Bank of New York, as Trustee for the 9 1/4% Senior Subordinated Notes due 2007 (incorporated by reference to Exhibit 4.1 to Registration Statement of Form S-4, File No. 333-26603) 4.2 Indenture dated as of October 28, 1997, between Cross Timbers Oil Company and the Bank of New York, as Trustee for the 8 3/4% Senior Subordinated Notes due 2009 (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-4, File No. 333-39097) 4.3 Preferred Stock Purchase Rights Agreement between Cross Timbers Oil Company and ChaseMellon Shareholder Services, LLC (incorporated by reference to Exhibit 4.1 to Form 8-A/A dated September 9, 1998) 4.4 Certificate of Designation of Series A Junior Participating Preferred Stock, par value $.01 per share, dated August 25, 1998 (incorporated by reference to Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2000) 10.1 * Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated May 17, 2000 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2000) 10.2 * Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated May 17, 2000 (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2000) 10.3 * Amended and Restated 1994 Stock Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 10-K for the year ended December 31, 1999) 10.4 * Form of grant under 1994 Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8, File No. 33-81766) 10.5 * 1997 Stock Incentive Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 1999) 10.6 * Form of grant under 1997 Stock Incentive Plan, as amended February 25, 1998 (incorporated by reference to Exhibit 10.9 to Form 10-K for the year ended December 31, 1997) 10.7 * 1998 Stock Incentive Plan, as amended February 20, 2001 10.8 * Form of grant under 1998 Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8, File No. 333-69977) 63 Exhibit No. Description Page ------- ---------------------------------------------------------- ------ 10.9 * Management Group Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 1999) 10.10 * Employee Severance Protection Plan, as amended February 15, 2000 (incorporated by reference to Exhibit 10.14 to Form 10-K for the year ended December 31, 1999) 10.11 Registration Rights Agreement among Cross Timbers Oil Company and partners of Cross Timbers Oil Company, L.P. (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-1, File No. 33-59820) 10.12 Warrant Agreement dated December 1, 1997 by and between Cross Timbers Oil Company and Amoco Corporation (incorporated by reference to Exhibit 10.11 to Form 10-K for the year ended December 31, 1997) 10.13 Revolving Credit Agreement dated May 12, 2000 between Cross Timbers Oil Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2000) 10.14 First Amendment, dated June 20, 2000, to Revolving Credit Agreement dated May 12, 2000 between Cross Timbers Oil Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2000) 10.15 Second Amendment, dated February 16, 2001, to Revolving Credit Agreement dated May 12, 2000 between Cross Timbers Oil Company and certain commercial banks named therein 12.1 Computation of Ratio of Earnings to Fixed Charges 21.1 Subsidiaries of Cross Timbers Oil Company 23.1 Consent of Arthur Andersen LLP 23.2 Consent of Miller and Lents, Ltd. * Management contract or compensatory plan -------------------------------- Copies of the above exhibits not contained herein are available, at the cost of reproduction, to any security holder upon written request to the Secretary, Cross Timbers Oil Company, 810 Houston St., Suite 2000, Fort Worth, Texas 76102. 64