-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VUN3cFSS3CbQhsNZojGVSTUzzUSdj9T+V8BEEAbMI7R92k86Ml8ZBNoIbt5YNLhF OhC2us1jNqhzgCOj/eaV1w== 0000930661-99-000778.txt : 19990412 0000930661-99-000778.hdr.sgml : 19990412 ACCESSION NUMBER: 0000930661-99-000778 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990409 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CROSS TIMBERS OIL CO CENTRAL INDEX KEY: 0000868809 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752347769 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-10662 FILM NUMBER: 99590277 BUSINESS ADDRESS: STREET 1: 810 HOUSTON ST STREET 2: STE 2000 CITY: FORT WORTH STATE: TX ZIP: 76102 BUSINESS PHONE: 8178702800 MAIL ADDRESS: STREET 1: 810 HOUSTON STREET STREET 2: STE 2000 CITY: FORT WORTH STATE: TX ZIP: 76102 10-K405/A 1 FORM 10-K/A AMENDMENT NO. 1 1998 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K/A Amendment No.1 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 ----------------- 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 New York Stock Exchange Series A convertible preferred stock, $.01 par value New York Stock Exchange
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. X ----- Aggregate market value of the voting stock held by nonaffiliates of the Registrant as of March 1, 1999 was approximately $222 million Number of Shares of Common Stock outstanding as of March 1, 1999 - 44,727,256 ---------- 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, 1999. ================================================================================ CROSS TIMBERS OIL COMPANY 1998 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 15 Part II 5. Market for Registrant's Common Equity and Related Stockholder Matters 16 6. Selected Financial Data.............................................. 17 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................ 19 7A. Quantitative and Qualitative Disclosures about Market Risk........... 27 8. Financial Statements and Supplementary Data.......................... 29 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................. 29 Part III 10. Directors and Executive Officers of the Registrant................... 29 11. Executive Compensation............................................... 29 12. Security Ownership of Certain Beneficial Owners and Management....... 29 13. Certain Relationships and Related Transactions....................... 29 Part IV 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...... 30
PART I Items 1. and 2. Business and Properties General Cross Timbers Oil Company and its wholly owned 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. The Company's proved reserves are principally located in relatively long-lived fields with well-established production histories concentrated in western Oklahoma, the East Texas Basin, the Permian Basin of West Texas and New Mexico, the Hugoton Field of Oklahoma and Kansas, the San Juan Basin of northwestern New Mexico, the Green River Basin of Wyoming and the Middle Ground Shoal Field of Alaska's Cook Inlet. The Company's estimated proved reserves at December 31, 1998 were 54.5 million barrels ("Bbls") of oil, 1.2 trillion cubic feet ("Tcf") of natural gas and 17.2 million Bbls of natural gas liquids, based on December 31, 1998 prices of $9.50 per Bbl for oil, $2.01 per thousand cubic feet ("Mcf") for gas and $3.99 per Bbl for natural gas liquids. Based on December 31, 1997 prices of $15.50 per Bbl for oil, and $2.20 per Mcf and $11.07 per Bbl for natural gas liquids, estimated proved reserves at December 31, 1998 would be 65.9 million Bbls of oil, 1.2 Tcf of natural gas and 17.7 million Bbls of natural gas liquids. This compares with December 31, 1997 proved reserves of 47.9 million Bbls of oil, 815.8 Bcf of natural gas and 13.8 million Bbls of natural gas liquids. Approximately 80% of December 31, 1998 proved reserves, computed on a gas energy equivalent ("Mcfe") basis, were proved developed reserves. Increased proved reserves during 1998 were primarily the result of predominantly gas- producing property acquisitions and development and exploitation activities, partially offset by production. During 1998, the Company's daily oil and gas production averaged 12,598 Bbls and 229,717 Mcf. Fourth quarter 1998 daily oil and gas production averaged 14,991 Bbls and 265,702 Mcf. Following its December 1997 acquisition of gas-producing properties in the San Juan Basin, the Company began separate reporting of natural gas liquids production. During 1998, daily natural gas liquids production averaged 3,347 Bbls per day. The Company's properties have relatively long reserve lives and highly predictable well production profiles. Based on December 31, 1998 proved reserves and projected 1999 production, the average reserve-to-production index of the Company's proved reserves is 12.6 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, 1998, the Company owned interests in 8,901 gross (3,281 net) wells and operated wells representing approximately 87% of the present value of cash flows before income taxes (discounted at 10%) from estimated proved reserves. The Company operates the majority of its properties, allowing it to control expenses, capital allocation and the timing of development and exploitation activities in its fields. This also allows the Company to reduce production costs on acquired properties. The Company has generated a substantial inventory of approximately 1,075 potential development drilling locations within its existing properties (of which 585 have been attributed proved undeveloped reserves), to support future net reserve additions. Approximately 200 of these locations will require certain regulatory approvals and legislation in Oklahoma prior to drilling. The Company's drilling plans are dependent upon product prices. In 1998, the Company began to emphasize exploration of unproved reserves as part of its business strategy. During the year, the Company expensed $8 million in connection with its exploration program, primarily including seismic and other geological and geophysical analysis costs. The Company has allocated less than 5% of its $60 million 1999 development budget for exploration activities. 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. 1 The Company operates a gas gathering system in Major County, Oklahoma, where a significant portion of the Company's gas is produced. Since August 1, 1995, the Company has also operated a gas gathering system and a gas processing plant in the Hugoton Field of Kansas and Oklahoma. Most of the Company's production is sold at current market prices. The Company also markets its oil and gas, including sales of gas under forward sales contracts and uses futures contracts and other price risk management instruments to hedge pricing risks. See Part II, Item 7A. The Company markets its gas production and the gas output of its gathering and processing systems. The Company arranges for some of its natural gas to be processed by unaffiliated third parties and markets the natural gas liquids from that processing. 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. Cross Timbers Oil Company completed its initial public offering of common stock in May 1993. During 1991, predecessors of the Company formed Cross Timbers Royalty Trust by carving net profits interests out of substantially all of the royalty and overriding royalty interests that the Company's predecessors then owned in Texas, New Mexico and Oklahoma, and seven nonoperated working interest properties in Texas and Oklahoma. The Company makes monthly net profits payments to Cross Timbers Royalty Trust based on revenues received and costs disbursed for the properties from which the net profits interests were carved. 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 ("Commission") to register the Company's 1,360,000 units for sale in a public offering. The filing of the registration statement has been made in anticipation of improving commodity prices and related market conditions for oil and gas equities. In December 1998, the Company formed the Hugoton Royalty Trust by conveying an 80% net profits interest in properties located in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These properties represent approximately 30% of the Company's existing reserve base. Hugoton Royalty Trust units will be listed on the New York Stock Exchange under the symbol "HGT." The Company filed a registration statement with the Commission in December 1998 and plans to offer approximately 40% of the Hugoton Royalty Trust units to the public in March or April 1999. Current Operating Environment The oil and gas industry is affected by many factors that the Company generally cannot control. Crude oil prices are generally determined by global supply and demand. After sinking to a five-year low at the end of 1993, oil prices reached their highest levels since the 1990 Persian Gulf War during fourth quarter 1996 and January 1997. Posted crude oil prices ranged from $17 to $20 during most of 1997, then declined to a $16 average in December 1997. Crude oil prices continued to decline throughout 1998, dropping to a West Texas Intermediate price of $8.00 per barrel in December 1998, the lowest level since 1978. This decline has been caused by low demand, as well as the failure of OPEC, at its November 1998 meeting, to further reduce production quotas. Low demand has been caused by warmer than normal winter temperatures and a slow recovery in Asian economies. Natural gas prices are influenced by national and regional 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. Generally because of colder weather, storage concerns and U.S. economic growth, prices remained relatively high during most of 1996 and 1997, reaching their highest levels since 1985. Gas prices declined, however, in December 1997 and have remained lower throughout 1998, primarily because the winters of 1997-1998 and 1998-1999 were abnormally mild in the central and eastern U.S. 2 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. 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, 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 cash resources. 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 development and drilling programs. The Company has generated an inventory of approximately 1,075 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 and drill development wells. Exploration Activities. During 1999, the Company will 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 less than 5% of its $60 million 1999 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, who were co-founders of the Company and its predecessors, 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 ("nonoperated interests") if such interests otherwise meet its acquisition criteria. The Company attempts to 3 acquire nonoperated interests in fields operated by established oil companies if these fields represent a significant investment to the operator and are therefore more likely to be carefully managed by it. The Company may also acquire nonoperated interests with the intent of ultimately accumulating, through future acquisitions, sufficient interests to obtain the right to operate the properties. The Company attempts to acquire nonoperated interests where geologic conditions indicate the potential for undeveloped reserves that the operator will exploit. The Company also attempts to acquire a portion of its oil and gas reserves in the form of royalty interests. Royalty interests offer less exposure to operational liabilities because they do not participate in operating activities and do not bear production or development costs. However, royalty interests typically allow only limited influence on the operation or development of properties. Royalty Trust Plan. In December 1998, the Company created the Hugoton Royalty Trust and plans to sell approximately 40% of the trust to the public in March or April 1999. The Company has announced its plans to create two additional royalty trusts, one for the San Juan Basin area and one for the Permian Basin area. Sales of royalty trust units will allow the Company to more efficiently capitalize its mature, lower growth properties. The remaining Company will continue its growth strategy by acquiring and developing properties that meet its acquisition criteria in order to grow its reserve base. Business Goals. In May 1998, the Company announced strategic goals for 1999, including increasing cash flow to $4.00 per share and proved reserves to 36 Mcfe per share, and reducing debt to 40 cents per Mcfe. These goals were based on commodity prices of $18 per Bbl of oil and $2.20 per Mcf of gas, net to the Company. For 1998, operating cash flow per share was $1.81, while year-end proved reserves per share were 36.7 Mcfe and debt per Mcfe was $0.56. While the Company believes it was on course with production and costs to achieve its cash flow goal, current lower commodity prices make its achievement unlikely in 1999. The Company's 1999 goal of reducing debt by as much as $300 million is expected to reduce debt per Mcfe to 40 to 45 cents. The Company plans to reduce debt with operating cash flow and proceeds from the sale of royalty trust units, producing properties and equity securities. The Company also announced its plans to make strategic acquisitions totaling $150 million from May 1998 through the end of 1999. After closing the Cook Inlet Acquisition in September 1998, the Seagull Acquisition in November 1998, and other smaller acquisitions in the last half of 1998, the Company has achieved approximately two-thirds of this goal. No further significant acquisitions are expected until the Company has substantially met its debt reduction goal. The Company has budgeted $60 million for its 1999 development program which is expected to be funded primarily by cash flow from operations. Exploration expenditures are expected to be less than 5% of the 1999 budget. The total capital budget, including acquisitions, will be adjusted throughout 1999 depending on oil and gas prices to capitalize on opportunities offering the highest rates of return. Acquisitions During 1995, the Company acquired predominantly gas-producing properties for a total cost of $131 million, and a gas processing plant and gathering facility for $29 million. The Santa Fe Acquisition, the largest of these acquisitions, closed on August 1, 1995 and consisted of mostly operated properties, a gas processing plant and gathering system in the Hugoton Field of Kansas and Oklahoma. The 1995 acquisitions increased proved reserves by approximately 3 million Bbls of oil and 171 Bcf of natural gas. 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. From July through December 1996, the Company acquired 955,800 units, or 16% of the publicly traded 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. 4 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 December 1, 1997 at an estimated adjusted purchase price of $195 million, including five-year warrants to purchase 937,500 shares of the Company's common stock at a price of $15.31 per share. This acquisition consists primarily of operated properties in the San Juan Basin of New Mexico. In May 1997, the Company acquired primarily gas-producing properties in Oklahoma, Kansas and Texas for an estimated 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 on April 24, 1998 at an estimated 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 1,921,850 shares of the Company's common stock along with certain price guarantees and a non-interest bearing note payable of $6 million, resulting in an estimated purchase price of $44.4 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 $29.2 million. The 1998 acquisitions increased reserves by approximately 16.3 million Bbls of oil and 311.3 Bcf of natural gas. 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, 1998 (in thousands):
Proved Reserves ------------------------------------ Discounted Natural Gas Present Value Liquids before Income Tax of Oil (Bbls) Gas (Mcf) (Bbls) Proved Reserves ---------- --------- ----------- --------------------- East Texas......... 2,127 317,947 - $234,825 25.8% San Juan Basin..... 1,199 253,568 17,174 170,868 18.8% Mid-Continent...... 4,495 189,374 - 163,282 18.0% Permian Basin...... 32,295 95,356 - 116,816 12.9% Rocky Mountain..... 2,481 183,830 - 110,390 12.1% Hugoton............ 232 159,128 - 89,745 9.9% Alaska Cook Inlet.. 11,437 - - 12,719 1.4% Other (a).......... 244 10,021 - 9,961 1.1% ------ --------- ------- -------- ---- Total.............. 54,510 1,209,224 17,174 $908,606 100% ====== ========= ======= ======== ====
(a) Includes 209,000 Bbls and 8,278,000 Mcf and discounted present value before income tax of $8,109,000 related to the Company's ownership of approximately 22% of Cross Timbers Royalty Trust units at December 31, 1998. Permian Basin Area Prentice Field. The Prentice Field is located in Terry and Yoakum Counties, Texas. In 1993 and 1994, the Company acquired its 91.5% working interest in the 178-well Prentice Northeast Unit in four separate transactions, resulting in the Company's assumption of operations of the unit effective March 1, 1994. The Company also owns an interest in 80 gross (1.7 net) nonoperated wells. 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. 5 During 1998, the Company drilled 1 gross (0.91 net) horizontal sidetrack in the Prentice Northeast Unit. The Company is currently studying additional areas in the unit for future development using horizontal technology. Ozona Area. The Company acquired interests in 1996 in the Henderson, Ozona, and Davidson Ranch fields located in Crockett County, Texas. The Company has interests in 125 gross (73.3 net) wells that it operates and 144 gross (30.2 net) wells operated by others. Oil and gas were first discovered in the Ozona area in 1962. Production is from the Pennsylvanian Canyon sandstones and Strawn carbonates at depths ranging from 6,500 to 9,000 feet. Development potential for this area includes infill drilling, field extension and delineation drilling, and possible horizontal drilling in the Strawn Formation. During 1998, the Company drilled a total of 18 gross (11.2 net) operated wells and participated in 3 gross (1.1 net) wells operated by others, making it one of the Company's most active gas development areas. The Company is currently evaluating 50 locations for possible future development. University Block 9. The University Block 9 Field is located in Andrews County, Texas. The Company owns a 100% working interest in 64 wells that it operates. The University Block 9 Field was discovered in 1953. Productive zones are of Wolfcamp, Pennsylvanian and Devonian age at 8,400, 8,700 and 10,400 feet, respectively. The Company operates the Wolfcamp Unit, Penn Unit and 33 of the 34 active Devonian wells. Development potential includes proper wellbore utilization, recompletions, infill drilling and improvement of waterflood efficiency. This field was the Company's most active oil development area during 1998, where the Company drilled 8 horizontal and vertical wells, 3 of which were being completed at year-end. The Company also recompleted four Devonian wells into the Pennsylvanian horizon. During 1999, the Company plans to drill up to 6 wells, depending on oil prices. An additional 30 to 40 locations have been identified for future development by either drilling or horizontal sidetrack. Mid-Continent Area A substantial portion of properties in the Mid-Continent area are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust as of December 1998. The Company plans to sell approximately 40% of its Hugoton Royalty Trust units in March or April 1999. Major County Area. The Company is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County, Oklahoma. The Company operates 496 gross (427.4 net) wells and has an interest in 251 gross (52.5 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, 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 1998, the Company participated in the drilling of 18 gross (14.0 net) wells in the western portion of the County, targeted at the Mississippian and Chester formations. The Company has budgeted 9 wells in Major County for 1999. 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 25,500 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 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 620 gross (590 net) wells which it operates and 123 gross (14.9 net) wells operated by others. The Company also owns the related gathering facilities. The East Texas properties also include more than 12,800 net undeveloped acres located primarily in Anderson County, Texas. During 1998, the Company drilled 10 net wells to the Travis peak formation, most of which were at various stages of completion at year end. The Company has identified over 170 drill well locations and over 300 workover and recompletion projects in this area. Approximately one-half of the Company's 1999 budget is directed to development in the East Texas area, including 75 workovers and 20 drill wells. Hugoton Area Most of the Company's properties in the Hugoton area are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust as of December 1998. The Company plans to sell approximately 40% of its Hugoton Royalty Trust units in March or April 1999. The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and Kansas and is the largest gas field in North America. It is estimated that five million productive acres exist in the entire field. The Company owns an interest in 399 gross (373.9 net) wells that it operates and 86 gross (20.4 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. In May 1996, the Company completed the installation of a field compressor on the south end of the Tyrone gathering system. The Company also completed the installation and start-up of a residue compressor and 11.5 miles of high pressure residue pipeline during August 1996. The installation of these facilities allows the Company to operate the Tyrone Plant more efficiently and allows access to three additional interstate pipelines. During 1998, the Company completed the acquisition of approximately 70 miles of low pressure gathering lines, adding 3,500 Mcf per day to the existing system. 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. The Oklahoma portion is drilled on 640-acre spacing. The Company believes that there are approximately 200 potential infill drilling locations, subject to regulatory approval and possibly new legislation being enacted in Oklahoma. During 1998, the Company drilled 15 gross (12.0 net) wells to the Chester, Council Grove and Chase formations. The Company plans to drill 13 wells during 1999. Rocky Mountain Area San Juan Basin. The San Juan Basin of northwestern New Mexico and southwestern Colorado contains the largest reserves of natural gas in the Rocky Mountains and, within North America, is second in size only to the Hugoton Field. The Company acquired most of its interests in the San Juan Basin in December 1997 from Amoco Corporation. The Company owns an interest in 644 gross (514.4 net) wells that it operates and 1,384 gross (186.1 net) wells operated by others. Of these wells, 66 gross (56.2 net) operated wells and 15 gross (2.8 net) non-operated wells are dual completions. During 1998, the Company participated in the drilling of 48 wells, completed 15 workovers and installed 78 wellhead compressors. The Company has identified over 300 drill well locations and over 100 workover and recompletion projects. During 1999, the Company plans to drill 41 wells (23 operated), recomplete 30 wells and install 40 wellhead compressors. 7 Green River Basin. The Green River Basin is located in southwestern Wyoming. The Company has interests in 174 gross (166.9 net) wells that it operates and 70 gross (9.4 net) wells operated by others in the Fontenelle, Nitchie Gulch and Pine Canyon fields. Substantially all properties in the Green River Basin are subject to an 80% net profits interest conveyed to the Hugoton Royalty Trust as of December 1998. The Company plans to sell approximately 40% of its Hugoton Royalty Trust units in March or April 1999. Gas production was discovered 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 1998, the Company drilled 20 net wells in the Fontenelle Unit and plans to drill approximately 5 wells during 1999. In 1997, the Company installed additional field compression to lower overall field operating pressures and to improve overall field performance. The Company also completed an interconnect to another pipeline in the southeastern part of the Fontenelle Field that added an additional market for the gas. 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 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 first 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. No significant development operations are anticipated in 1999. The Company is conducting engineering and geologic studies, the results of which should be implemented in 2000, depending on oil prices. 8 Reserves The following are estimated quantities of proved reserves and cash flows therefrom as of December 31, 1998, 1997 and 1996:
December 31 ---------------------------------- 1998 1997 1996 ---------- ---------- ---------- (in thousands) Proved developed: Oil (Bbls)......................... 42,876 33,835 31,883 Gas (Mcf).......................... 968,495 677,710 466,412 Natural gas liquids (Bbls)......... 14,000 11,494 - Proved undeveloped: Oil (Bbls)......................... 11,634 14,019 10,557 Gas (Mcf).......................... 240,729 138,065 74,126 Natural gas liquids (Bbls)......... 3,174 2,316 - Total proved: Oil (Bbls)......................... 54,510 47,854 42,440 Gas (Mcf).......................... 1,209,224 815,775 540,538 Natural gas liquids (Bbls)......... 17,174 13,810 - Estimated future net cash flows: Before income tax.................. $1,677,426 $1,484,542 $1,737,024 After income tax................... $1,446,177 $1,193,167 $1,286,037 Present value of estimated future net cash flows, discounted at 10%: Before income tax.................. $ 908,606 $ 782,322 $ 946,150 After income tax................... $ 808,403 $ 642,109 $ 706,481
Miller and Lents, Ltd. ("Miller and Lents"), 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, 1998, 1997 and 1996. 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. Based on December 31, 1997 prices of $15.50 per Bbl for oil, $2.20 per Mcf and $11.07 per Bbl for natural gas liquids, estimated proved reserves at December 31, 1998 would be 65.9 million Bbls of oil, 1.2 Tcf of natural gas and 17.7 million Bbls of natural gas liquids. See Note 14 to Consolidated Financial Statements for additional information regarding estimated proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. 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 1998, the Company filed estimates of oil and gas reserves as of December 31, 1997 with the U.S. Department of Energy on Form EIA-23. These estimates are consistent with the reserve data reported in Note 14 to Consolidated Financial Statements for the year ended December 31, 1997, with the exception that Form EIA-23 includes only reserves from properties operated by the Company. 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. 9 Producing Wells The following table summarizes the Company's producing wells as of December 31, 1998, all of which are located in the United States:
Operated Wells Non-Operated Wells Total (a) ----------------- ------------------ ----------------- Gross Net Gross Net Gross Net ------- ------- ------- ------- ------- ------- Oil........... 642 589.7 3,595 203.2 4,237 792.9 Gas........... 2,480 2,155.4 2,184 333.1 4,664 2,488.5 ----- ------- ----- ----- ----- ------- Total......... 3,122 2,745.1 5,779 536.3 8,901 3,281.4 ===== ======= ===== ===== ===== =======
(a) Two gross (1.5 net) oil wells and 86 gross (60 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, 1998, the Company was in the process of drilling 52 gross (33.8 net) wells.
Year Ended December 31 -------------------------------------- 1998 1997 1996 ----------- ------------ ----------- Gross Net Gross Net Gross Net ----- ---- ----- ----- ----- ---- Development wells: Completed as- Oil wells........ 53 14.1 82 53.4 92 45.5 Gas wells........ 139 63.4 119 85.9 70 38.1 Non-productive..... 1 - 5 3.2 4 2.7 --- ---- ---- ----- --- ---- Total.............. 193 77.5 206 142.5 166 86.3 --- ---- ---- ----- --- ---- Exploratory wells: Completed as- Gas wells........ 3 3.0 2 0.6 - - Non-productive..... 2 1.0 1 0.1 - - --- ---- ---- ----- --- ---- Total.............. 5 4.0 3 0.7 - - --- ---- ---- ----- --- ---- Total (a)........... 198 81.5 209 143.2 166 86.3 === ==== ==== ===== === ====
(a) Included in totals are 118 gross (14.6 net) wells in 1998, 57 gross (6.9 net) wells in 1997 and 85 gross (10.4 net) wells in 1996 drilled on nonoperated interests. Excluded from above totals are 21 gross (0.4 net) carbon dioxide wells drilled on non-operated interests in 1996. 10 Acreage The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest as of December 31, 1998. Excluded from this summary is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests.
Developed (a)(b) Undeveloped ------------------ ------------------- Gross Net Gross Net --------- ------- ------ ----------- Oklahoma.... 355,303 289,225 15,821 7,143 Texas....... 268,264 172,859 36,489 25,041 New Mexico.. 232,205 172,049 5,094 4,030 Kansas...... 80,225 67,951 -0- -0- Wyoming..... 56,583 34,933 2,811 1,906 Other....... 41,699 28,737 31,053 23,876 --------- ------- ------ ------ Total....... 1,034,279 765,754 91,268 61,996 ========= ======= ====== ======
(a) "Developed acres" are acres spaced or assignable to productive wells. (b) Certain leasehold 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 6 Mcf to 1 Bbl):
Year Ended December 31 ---------------------- 1998 1997 1996 ------ ------ ------ Sales prices:............................. Oil (per Bbl)........................... $12.21 $18.90 $21.38 Gas (per Mcf)........................... $ 2.07 $ 2.20 $ 1.97 Natural gas liquids (per Bbl)........... $ 7.62 $ 9.66 $ - Production costs per Mcfe................. $ 0.53 $ 0.59 $ 0.67 Taxes, transportation and other per Mcfe.. $ 0.25 $ 0.22 $ 0.20
Delivery Commitments The Company contracted to sell to a single purchaser approximately 11,650 Mcf of gas per day through May 2000 and 21,650 Mcf of gas per day from June 2000 through July 2005. Deliveries under this contract are generally in Oklahoma. The Company has committed to sell all gas production from certain properties in the East Texas Basin Acquisition 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. Under the terms of its amended purchase and sale agreement with Shell for the Cook Inlet Acquisition, the Company has committed to sell to Shell, beginning March 1, 1999, the following minimum daily natural gas volumes: 42,000 Mcf in 1999, 40,000 Mcf in 2000, 37,500 Mcf in 2001, 36,500 Mcf in 2002 and 35,000 Mcf in 2003. Delivery 11 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. 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. Because gathering systems are the only practical method for the intermediate transportation of natural gas, 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 nature of the Company's oil and gas reserves and management's 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 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"). The Company's gathering systems and 26-mile pipeline have been declared exempt from FERC jurisdiction, and therefore, the Company's gathering service is not regulated by FERC. Federal wellhead price controls on all domestic gas were terminated on January 1, 1993. The Company cannot predict the impact of government regulation on any natural gas facilities. In 1992, FERC issued Orders Nos. 636 and 636-A, requiring operators of pipelines to unbundle transportation services from sales services and allow customers to pay for only the services they require, regardless of whether the customer purchases gas from such pipelines or from other suppliers. The United States Court of Appeals upheld the unbundling provisions and other components of FERC's orders but remanded several issues to FERC for further explanation. On February 27, 1997, FERC issued Order No. 636-C, addressing the Court's concern. Petitions for rehearing on Order No. 636-C were denied on May 28, 1998. FERC's order remains subject to judicial review and may be changed as a result of that review. 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 impact of these regulations on marketing the Company's production or on its gas transportation business cannot be predicted. The Company, however, 12 does not believe that it will be affected any differently than other natural gas producers and marketers with which it competes. 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. The Energy Policy Act of 1992 required the FERC to adopt a simplified ratemaking methodology for interstate oil pipelines. In 1993 and 1994, the FERC issued Order Nos. 561 and 561-A, adopting rules that establish new rate methods for such pipelines. Under the new rules, effective January 1, 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, if any, effect on the Company with respect to the cost of moving oil to market. 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 or locations that can be drilled. The Company may become 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 regulations with respect to gathering systems. New regulations passed 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 Indian Leases The Company's operations on federal, state or Indian 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. Employees The Company had 521 employees as of December 31, 1998. None of the Company's employees are represented by a union. The Company considers its relations with its employees to be good. 13 Executive Officers of the Company The officers of the Company are elected by and serve until their successors are elected by the Board of Directors. Bob R. Simpson, 50, 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, 48, 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. J. Richard Seeds, 53, has been a director of the Company since July 1996 and has served as Executive Vice President since May 1997. Mr. Seeds previously was Career Guidance Counselor with the Springtown Independent School District (1993-1997), an independent personal investment manager and consultant to the San Juan Basin Royalty Trust, the Permian Basin Royalty Trust and the Cross Timbers Royalty Trust (1986-1993). Mr. Seeds was Vice President of Finance and Controller (1979-1986) and Controller (1977-1979) of Southland Royalty Company. Louis G. Baldwin, 49, has been Senior 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, 40, has been Senior Vice President - Asset Development or held similar positions with the Company since 1987. From 1982 to 1987, Mr. Hutton was a Reservoir Engineer with Sun Exploration & Production Company. Bennie G. Kniffen, 48, 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. Larry B. McDonald, 52, has been Senior Vice President - Operations or held similar positions with the Company since 1990. Prior to that time, Mr. McDonald owned and operated McDonald Energy, Inc. (1986-1990). Timothy L. Petrus, 44, has been Senior Vice President - Acquisitions or held similar positions with the Company since 1988. Prior to that time, Mr. Petrus was a Vice President with Texas American Bank (1980-1988) and was a Senior Project Engineer with Exxon (1976-1980). Kenneth F. Staab, 42, has been Senior Vice President of Engineering or held similar positions with the Company since 1986. Prior to that time, Mr. Staab was a Reservoir Engineer with Southland Royalty Company (1982-1986). Thomas L. Vaughn, 52, has been Senior Vice President - Operations or held similar positions with the Company since 1988. From 1986 to 1988, Mr. Vaughn owned and operated Vista Operating Company. Vaughn O. Vennerberg II, 44, has been Senior Vice President - Land 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). 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 arms-length transactions, which 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. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. The Company filed motions to dismiss the action due to lack of proper venue, which motions were denied. This decision denying the motions is being appealed. 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 Company was not made aware of the claim until the U.S. Justice Department contacted the Company in August 1998. 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. According to the U.S. Justice Department, the plaintiff has made similar allegations in actions filed against over 300 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 Company has not been served with this complaint which is under review by the U.S. Justice Department. The Company has filed a response with the U.S. Justice Department and is awaiting its decision whether to intervene in the case. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. The Company and certain of its subsidiaries are 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, liquidity or operations. 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 1998. 15 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 1998 and 1997 (as adjusted for the three-for-two stock splits effected on March 19, 1997 and February 25, 1998):
High Low Dividends --------- --------- --------- 1998 First Quarter... $ 21.125 $ 14.672 $.040 Second Quarter.. 20.875 16.375 .040 Third Quarter... 19.313 11.375 .040 Fourth Quarter.. 16.813 5.063 .040 1997 First Quarter... $ 13.719 $ 10.422 $.037 Second Quarter.. 13.750 9.828 .037 Third Quarter... 16.375 12.328 .037 Fourth Quarter.. 19.125 13.297 .037
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 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 16, 1999, the Board of Directors reduced the Company's quarterly dividend to $.01 per share from $.04 payable on April 15, 1999 to shareholders of record on March 31, 1999. The reduction was made in response to the low commodity price environment and the Company's 1999 goal to reduce debt by $300 million. On March 1, 1999, the Company had 547 shareholders of record. 16 Item 6. Selected Financial Data The following table shows selected financial information for the five years ended December 31, 1998. 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 and February 1998. 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).
1998 1997 1996 1995 1994 -------------- ----------- ----------- ------------- --------- (in thousands except production, per share and per unit data) Consolidated Statement of Operations Data Revenues:.................................... Oil and condensate.......................... $ 56,164 $ 75,223 $ 75,013 $ 60,349 $ 53,324 Gas and natural gas liquids................. 182,587 110,104 73,402 40,543 38,389 Gas gathering, processing and marketing..... 9,438 9,851 12,032 7,091 4,274 Other....................................... 1,297 3,094 888 3,362 288 --------- ---------- --------- --------- -------- Total Revenues.............................. $ 249,486 $ 198,272 $ 161,335 $ 111,345 $ 96,275 ========== ========== ========= ========= ======== Earnings (loss) available to common stock.... $ (71,498) (a) $ 23,905 $ 19,790 (1,538) (b) $ 3,048 ========== ========== ========= ========= ======== Per common share Basic....................................... $ (1.65) (a) $ 0.60 $ 0.50 $ (0.28) (b) $ 0.09 ========== ========== ========= ========= ======== Diluted..................................... $ (1.65) (a) $ 0.59 $ 0.48 $ (0.28) (b) $ 0.08 ========== ========== ========= ========= ======== Weighted average common shares outstanding... 43,396 39,773 39,913 38,072 35,829 ========== ========== ========= ========= ======== Dividends declared per common share.......... $ 0.16 $ 0.15 $ 0.13 $ 0.13 $ 0.13 ========== ========== ========= ========= ======== Consolidated Statement of Cash Flows Data Cash provided (used) by: Operating activities........................ $ (45,842) $ 98,006 $ 59,694 $ 32,938 $ 42,293 Investing activities........................ $ (384,598) $ (311,322) $(124,871) $(160,416) $(62,745) Financing activities........................ $ 438,957 $ 213,195 $ 66,902 $ 121,852 $ 26,232 Consolidated Balance Sheet Data............... Property and equipment, net.................. $1,051,011 $ 723,836 $ 450,561 $ 364,474 $244,555 Total assets................................. $1,207,594 $ 788,455 $ 523,070 $ 402,675 $292,451 Long-term debt............................... $ 921,000 $ 539,000 $ 314,757 $ 238,475 $142,750 Stockholders' equity......................... $ 177,451 $ 170,243 $ 142,668 $ 130,700 $113,333 Operating Data................................ Average daily production:.................... Oil (Bbls).................................. 12,598 10,905 9,584 9,677 9,497 Gas (Mcf)................................... 229,717 135,855 101,845 78,408 58,182 Natural gas liquids (Bbls).................. 3,347 220 - - - Mcfe........................................ 325,390 202,609 159,349 136,470 115,164 Average sales price:......................... Oil (per Bbl)............................... $ 12.21 $ 18.90 $ 21.38 $ 17.09 $ 15.38 Gas (per Mcf)............................... $ 2.07 $ 2.20 $ 1.97 $ 1.42 $ 1.81 Natural gas liquids (per Bbl)............... $ 7.62 $ 9.66 - - - Production expense (per Mcfe)................ $ 0.53 $ 0.59 $ 0.67 $ 0.71 $ 0.77 Taxes, transportation and other (per Mcfe)... $ 0.25 $ 0.22 $ 0.20 $ 0.17 $ 0.21 Proved reserves:............................. Oil (Bbls).................................. 54,510 47,854 42,440 39,988 33,581 Gas (Mcf)................................... 1,209,224 815,775 540,538 358,070 177,061 Natural gas liquids (Bbls).................. 17,174 13,810 - - - Mcfe........................................ 1,639,331 1,185,759 795,178 597,998 378,547 Other Data Operating cash flow (c)...................... $ 78,480 $ 89,979 $ 68,263 $ 40,439 $ 37,816 Ratio of earnings to fixed charges (d)....... (0.7) (e) 2.2 2.6 (0.2) (f) 1.5
17 (a) 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. (b) Includes effect of a $20.3 million pre-tax, non-cash impairment charge recorded upon adoption of Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. (c) Defined as cash provided by operating activities before changes in current assets and liabilities. Because of exclusion of changes in current assets and liabilities, this cash flow statistic is different from cash provided (used) by operating activities, as is disclosed under generally accepted accounting principles. (d) For purposes of calculating this ratio, earnings include income (loss) from continuing operations before income tax and fixed charges. Fixed charges include interest expense, the portion of rentals (calculated as one-third) considered to be representative of the interest factor and preferred stock dividends. (e) Includes effect of the items in (a) above. Excluding the effect of these items, the ratio of earnings to fixed charges is 0.8. (f) Includes effect of the charge in (b) above. Excluding the effect of this charge, the ratio of earnings to fixed charges is 1.3. 18 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. General The following events affect the comparability of results of operations and financial condition for the years ended December 31, 1998, 1997 and 1996, 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 quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf. Three-for-Two Stock Splits. The Company effected a three-for-two stock split on March 19, 1997 and on February 25, 1998. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect both stock splits. 1998 Acquisitions. During 1998, the Company acquired oil- and gas-producing properties for a total cost of $340 million, including: - The East Texas Basin Acquisition. The Company acquired these primarily gas-producing properties for an estimated purchase price of $245 million, later reduced to $215 million by a $30 million production payment sold to EEX Corporation. This acquisition closed on April 24, 1998 and was funded by bank debt, partially repaid from proceeds of the 1998 Common Stock Offering. - The Alaska Cook Inlet Acquisition. In September 1998, the Company acquired these oil-producing properties in exchange for 1,921,850 shares of the Company's common stock along with certain price guarantees and a non-interest bearing note payable of $6 million, resulting in an estimated purchase price of $44.4 million. - The Seagull Acquisition. This acquisition includes 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 $29.2 million, funded by bank borrowings. 1997 Acquisitions. During 1997, the Company acquired predominantly gas- producing properties for a total cost of $256 million, funded primarily by bank borrowings and cash flow from operations. The acquisitions include: - The Amoco Acquisition. The Company purchased these properties in the San Juan Basin of New Mexico in December 1997 for an estimated adjusted purchase price of $195 million. This purchase price includes $5.7 million for five-year warrants to purchase 937,500 shares of the Company's common stock at $15.31 per share. - The Burlington Resources Acquisition. The Company purchased these properties in Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39 million in May 1997. - 6% of the publicly traded outstanding units in Cross Timbers Royalty Trust, at a cost of $5.4 million. 1996 Acquisitions. During 1996, the Company acquired primarily gas-producing properties for a total cost of $106 million funded primarily by bank debt. These acquisitions include: - The Enserch Acquisition. This acquisition closed in July 1996 at a cost of $39.4 million and primarily consisted of operated gas-producing properties 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. - Gas-producing properties in the Ozona area of the Permian Basin of West Texas. The Company acquired these mostly operated interests for $28.1 million. 19 - 16% of the publicly traded outstanding units in Cross Timbers Royalty Trust. The Company purchased these units at a total cost of $12.8 million from July through December 1996. 1998, 1997 and 1996 Development and Exploration Programs. Oil development was concentrated in the University Block 9 Field during 1998 and 1997, as well as the Prentice Northeast Unit of West Texas during 1997 and 1996. Gas development focused on the Hugoton Area during 1998, the Ozona Area in 1998 and 1997, the Fontenelle Unit during all three years and Major County, Oklahoma during 1996. Exploration activity during 1998 was primarily geological and geophysical analysis, including seismic studies, of undeveloped properties at a total cost of $8 million. This work was concentrated in the Silurian Reef of Illinois, and Texas County and the Nemeha Ridge Area of Oklahoma. Exploratory expenditures were $2.1 million in 1997 and insignificant in 1996. 1999 Development and Exploration Program. The Company has budgeted $60 million for its 1999 development and exploration program, which is expected to be funded primarily by cash flow from operations. The Company anticipates exploration expenditures will be less than 5% of the 1999 budget. The total capital budget, including acquisitions, will be adjusted throughout 1999 to capitalize on opportunities offering the highest rates of return. 1998 Common Stock Offering. In April 1998, the Company sold 7,203,450 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. 1998 Issuance of Common Shares. In September 1998, the Company issued from treasury stock 1,921,850 common shares to subsidiaries of Shell Oil Company for the Alaska Cook Inlet Acquisition. 1997 Senior Subordinated Note Sales. The Company sold $125 million of 9 1/4% senior subordinated notes in April 1997 and $175 million of 8 3/4% senior subordinated notes in October 1997. Net proceeds of $121.1 million and $169.9 million were used to reduce bank debt. 1997 and 1996 Conversion of Subordinated Notes. During November and December 1996, noteholders converted $27.7 million principal of the 5 1/4% convertible subordinated notes into 2,696,521 shares of common stock. In January 1997, noteholders converted the remaining principal of $29.7 million into 2,892,363 shares of common stock. 1996 Preferred Stock Exchange. In September 1996, stockholders exchanged 2,979,249 shares of common stock for 1,138,729 shares of Series A convertible preferred stock pursuant to the Company's exchange offer. Treasury Stock Purchases. Since May 1996, the Board of Directors has authorized the purchase of a total of 10.5 million shares of the Company's common stock as part of its strategic acquisition plans. The Company purchased on the open market 4.3 million shares at a cost of $65.6 million in 1998, 2.4 million shares at a cost of $28 million in 1997 and 2.9 million shares at a cost of $30.7 million in 1996. Investment in Equity Securities. The Company acquired common stock of publicly traded independent oil and gas producers at a total cost of $167.7 million in 1998, $6.5 million in 1997 and $16.1 million in 1996. For accounting purposes, the Company considered equity securities purchased in 1998 to be trading securities, whereas it considered equity securities purchased prior to 1998 to be available-for-sale securities. Accordingly, the Company recognized unrealized investment gains and losses in its 1998 statement of operations, as opposed to recording as a component of stockholders' equity in prior years. During 1998, the Company recognized a $93.7 million loss on investment in equity securities, including a loss on sale of securities of $14.8 million, an unrealized loss of $72.6 million and interest expense of $6.3 million related to the investment. During 1997, the Company recognized a gain of $1.7 million on its investment in equity securities including a gain on sale of securities of $2.4 million and interest expense of $700,000 related to the investment. Property Sales. The Company sold producing properties resulting in net gains of $800,000 in 1998, $1.8 million in 1997 and $500,000 in 1996. Stock Incentive Compensation. Stock incentive compensation results from stock appreciation right ("SAR") and performance share awards, and subsequent changes in the Company's stock price. During 1998, stock incentive compensation totaled $1.3 million, which included non-cash performance share compensation of $1.6 million, partially offset by a reduction in SAR compensation of $300,000. In 1997, stock incentive compensation totaled $3.7 million, 20 which included non-cash performance share compensation of $3.3 million and SAR compensation of $400,000. During 1996, stock incentive compensation totaled $6.2 million, which included SAR compensation of $3.7 million (cash payments of $7.1 million, partially offset by prior accruals) and non-cash performance share compensation of $2.5 million. Exercises and forfeitures under the 1991 Stock Incentive Plan reduced outstanding stock incentive units (including SARs) from 836,000 at the beginning of 1996 to 18,000 at year-end 1998. Product Prices. In addition to supply and demand, oil and gas prices are affected by substantial seasonal, political and other fluctuations the Company generally cannot control or predict. Crude oil prices are generally determined by global supply and demand. After sinking to a five-year low at the end of 1993, oil prices reached their highest levels since the 1990 Persian Gulf War during fourth quarter 1996 and January 1997. Crude oil prices ranged from $17 to $20 during most of 1997, then declined to a $16 average in December. Crude oil prices continued to decline throughout 1998, dropping to a West Texas Intermediate price of $8.00 per barrel in December 1998, the lowest level since 1978. This decline is the result of low demand, as well as the failure of OPEC, at its November 1998 meeting, to further reduce production quotas. Low demand has been caused by warmer than normal winter temperatures and a slower than expected recovery in Asian economies. Based on 1998 production, the Company estimates that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $4.4 million change in 1999 annual operating cash flow. Natural gas prices are influenced by national and regional supply and demand, which is often dependent upon weather conditions. Specific gas prices are also based on the location of production, pipeline capacity, gathering charges and the energy content of the gas. Generally because of colder weather, storage concerns and U.S. economic growth, prices remained relatively high during most of 1996 and 1997, reaching their highest levels since 1985. Gas prices declined, however, in December 1997 and, except for a rebound during the summer, have remained lower throughout 1998. Lower gas prices have been primarily because the winters of 1997-1998 and 1998-1999 in the central and eastern U.S. were abnormally mild. The Company has entered into commodity price hedging instruments to reduce its exposure to gas price fluctuations. As a result of these commodity hedging instruments, the Company's average gas price increased from $1.97 to $2.07 in 1998 and decreased from $2.24 to $2.20 in 1997. Based on 1998 production, the Company estimates that a $0.10 per Mcf increase or decrease in the average gas sales price would result in approximately a $7.7 million change in 1999 annual operating cash flow. 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 remain at lower levels or decline further, the Company may be required to record impairment provisions in the future, which may be material. Results of Operations 1998 Compared to 1997 For the year 1998, loss available to common stock was $71.5 million compared with earnings of $23.9 million for 1997. The 1998 loss includes a $93.7 million loss ($61.8 million after tax) on investment in equity securities and a $2 million ($1.3 million after tax) impairment write-down of producing properties. The remaining decline in earnings is primarily the result of lower product prices and increased interest related to the 1998 acquisitions and treasury stock purchases. Revenues for 1998 were $249.5 million, or 26% above 1997 revenues of $198.3 million. Even though oil production increased by 16%, oil revenue decreased $19.1 million or 25% because of a 35% decrease in oil prices from an average of $18.90 in 1997 to $12.21 in 1998 (see "General-Product Prices" above). Increased production was primarily because of the 1998 acquisitions. Gas revenue increased $72.5 million or 66% because of a 69% increase in production partially offset by a 6% price decrease (see "General-Product Prices" above). Increased gas production was attributable to the 1997 and 1998 acquisitions and development programs. Gas revenues for 1998 also included $9.3 million from San Juan Basin natural gas liquids production attributable to the December 1997 Amoco Acquisition. 21 Gas gathering, processing and marketing revenues decreased $400,000 primarily because of decreased wellhead volumes and lower gas and natural gas liquids prices, partially offset by increased margin. Other revenues were $1.8 million lower primarily because of decreased net gains on sale of properties and decreased lawsuit settlement receipts. Expenses for 1998 totaled $209.2 million as compared with total 1997 expenses of $134.8 million. Most expenses increased in 1998 primarily because of the 1997 and 1998 acquisitions and exploration and development programs. Production expense increased $19.6 million or 45%. Per Mcfe, production expense decreased from $0.59 to $0.53. This decrease is primarily because of the lower operating costs of gas-producing properties acquired in 1997 and 1998, the timing of workovers and operating efficiencies initiated after acquiring operated properties. Exploration expenses for 1998 totaled $8 million and were predominantly geological and geophysical costs, including seismic analysis, related to the 1998 exploration program. Exploration costs in 1997 totaled $2.1 million. Taxes on production and property, transportation and other deductions increased 77% or $12.7 million because of increased oil and gas revenues, as well as increased property taxes related to the 1997 and 1998 acquisitions. Taxes, transportation and other per Mcfe increased 14% from $0.22 to $0.25 because of increased transportation, compression and other charges related to acquisitions. Depreciation, depletion and amortization ("DD&A") increased $35.8 million, or 75%, primarily because of the 1997 and 1998 acquisitions and development programs. On an Mcfe basis, DD&A increased from $0.65 in 1997 to $0.70 in 1998 primarily because of the higher cost per Mcfe of the 1998 acquisitions. General and administrative expense decreased $2.3 million, or 15%, because of a $2.4 million decrease in stock incentive compensation, partially offset by increased expenses from Company growth. Excluding stock incentive compensation, general and administrative expense per Mcfe decreased to $0.10 in 1998 from $0.16 in 1997. This reduction resulted from production growth outpacing Company personnel requirements and other administrative expenses. Interest expense increased $26.1 million or 100% primarily because of a comparable increase in weighted average borrowings to partially fund the 1997 and 1998 acquisitions and treasury stock purchases, combined with a 1% increase in the weighted average interest rate and amortization of loan fees. 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 from $0.35 in 1997 to $0.44 in 1998 primarily as the result of an increase in the weighted average borrowings to fund treasury stock purchases. 1997 Compared to 1996 Earnings available to common stock for 1997 were $23.9 million as compared with $19.8 million for 1996. Improved earnings were primarily the result of higher gas prices and increased gas production from the 1996 and 1997 acquisitions and development programs. Results included the effects of stock incentive compensation of $3.7 million in 1997 and $6.2 million in 1996. Also included in 1997 results were a $1.7 million gain on investment in equity securities, a gain of $1.8 million on sale of properties and lawsuit settlement proceeds of $1.3 million. A $500,000 gain on sale of properties was included in 1996 results. Dividends on preferred stock issued in September 1996 reduced 1997 earnings by $1.8 million and 1996 earnings by $500,000. Revenues for 1997 were $198.3 million, or 23% above 1996 revenues of $161.4 million. Oil revenue remained constant as a 13% increase in oil production was offset by a 12% decrease in oil prices from an average of $21.38 in 1996 to $18.90 in 1997 (see "General-Product Prices" above). Increased production was primarily because of the 1997 acquisitions and development programs. Gas revenue increased $36.7 million or 50% because of a 33% increase in production combined with a 12% price increase (see "General-Product Prices" above). Increased gas production was attributable to the 1996 and 1997 acquisitions and development programs. Gas revenues for 1997 also included $800,000 from San Juan Basin natural gas liquids production attributable to the December 1997 Amoco Acquisition. 22 Gas gathering, processing and marketing revenues decreased $2.2 million primarily because of a decrease in margin and gas volumes. Other revenues increased $2.2 million primarily because of increased net gains on sale of properties and lawsuit settlement proceeds received in 1997. Expenses for 1997 totaled $134.8 million as compared with total 1996 expenses of $113.3 million. All expenses other than general and administrative expense increased in 1997 primarily because of the 1996 and 1997 acquisitions and exploration and development programs. Production expense increased $4.2 million or 11%. Production expense per Mcfe decreased from $0.67 to $0.59. This decrease is primarily because of the lower operating costs of gas-producing properties acquired in 1996 and 1997, the timing of workovers and operating efficiencies initiated after acquiring operated properties. Exploration expenses for 1997 totaled $2.1 million, and were predominantly geological and geophysical costs related to the 1997 exploration program. Exploration costs in 1996 and prior were included in production expense since not significant. Taxes on production and property, transportation and other deductions increased 37% or $4.5 million because of increased oil and gas revenues, as well as increased property taxes related to the 1996 and 1997 acquisitions. Taxes, transportation and other per Mcfe increased 10% from $0.20 to $0.22 because of increased gas prices and higher property tax rates. DD&A increased $9.9 million, or 26%, primarily because of the 1996 and 1997 acquisitions and development programs. On an Mcfe basis, DD&A remained relatively flat at $0.65 for 1996 and 1997. General and administrative expense decreased $600,000, or 4%, because of a $2.5 million decrease in stock incentive compensation, partially offset by increased expenses from Company growth. Excluding stock incentive compensation, general and administrative expense per Mcfe was $0.16 for 1997 as compared with $0.17 for 1996. Gas gathering and processing expense increased $1.6 million or 23%. This increase was primarily because of rental expense related to the Tyrone plant and gathering system lease that began in March 1996 and the Major County, Oklahoma gathering system lease that began in November 1996. This increase offsets related decreases in DD&A and interest. Interest expense increased $9.9 million or 61% because of a 36% increase in weighted average borrowings to partially fund the 1996 and 1997 acquisitions and purchases of treasury stock, combined with a 20% increase in the weighted average interest rate primarily attributable to the senior subordinated notes sold in April and October 1997. Interest expense per Mcfe increased from $0.28 in 1996 to $0.35 in 1997, primarily because of an increase in the weighted average interest rate, as well as the result of increased bank debt to finance treasury stock purchases. 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. The Company believes that its sources of liquidity are adequate to fund its 1999 cash requirements. Cash used by operating activities was $45.8 million in 1998, compared with $98 million cash provided by operations in 1997 and $59.7 million in 1996. The fluctuation from 1997 to 1998 was primarily because of decreased product prices and purchases of equity securities, net of sales. Before changes in working capital, cash flow from operations was $78.5 million in 1998, $90 million in 1997 and $68.3 million in 1996. The 1997 and 1996 acquisitions were primarily financed by long-term debt. The 1998 acquisitions were funded by a combination of bank borrowings, proceeds from a public offering of common stock and the issuance of common stock. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. 23 Financial Condition Total assets increased 53% from $788 million at December 31, 1997 to $1.2 billion at December 31, 1998, primarily because of the 1998 acquisitions. As of December 31, 1998, total capitalization of the Company was $1.1 billion, of which 84% was long-term debt. This compares with capitalization of $709 million at December 31, 1997, of which 76% was long-term debt. The increase in the debt-to-capitalization ratio from year-end 1997 to 1998 is because of increased borrowings under the Company's loan agreement to fund the 1998 acquisitions, purchases of equity securities and other capital expenditures (see "Financing" below). 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. Working capital of $38 million at December 31, 1998 is primarily attributable to the investment in equity securities and the related deferred tax benefit. Financing On November 16, 1998, the Company entered into a new Revolving Credit Agreement with commercial banks. As of December 31, 1998, the Company had a borrowing base and commitment of $615 million with no unused borrowing capacity under the loan agreement. The interest rate on borrowings at December 31, 1998 was 6.9%. The Company periodically renegotiates the loan agreement to increase the borrowing commitment and extend the revolving facility; however, the Company cannot assure that it can continue to do so in the future. The Company's goal in 1999 is to reduce debt by as much as $300 million, resulting in debt of 40 to 45 cents per Mcfe of proved reserves. 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. Otherwise, borrowings under the loan agreement do not mature until June 30, 2003, but may be prepaid at any time without penalty. The borrowing base is scheduled to be redetermined in June 1999. Based on year-end proved reserves, the Company does not expect a reduction in the borrowing base upon its redetermination. Other financing activities in 1998, 1997 and 1996 included the 1998 common stock offering, 1998 issuance of common shares, 1997 senior subordinated note sales, 1997 and 1996 conversion of subordinated notes and 1996 preferred stock exchange. These transactions are described under "General" above. Capital Expenditures In May 1998, the Company announced plans to make strategic acquisitions totaling $150 million from May 1998 through the end of 1999. After closing the Alaska Cook Inlet Acquisition in September, the Seagull Acquisition in November and other smaller acquisitions in the last half of 1998, the Company achieved approximately two-thirds of this goal. The Company does not expect to make further significant acquisitions until substantially meeting its debt reduction goal. The Company plans to fund any future acquisitions through a combination of cash flow from operations and proceeds from bank debt, public equity or debt transactions. In 1998, exploration and development cash expenditures totaled $77.4 million compared with the budget of $90 million. In 1997, exploration and development cash expenditures totaled $90.5 million, compared with the budget of $70 million. The Company has budgeted $60 million for the 1999 development program. As it has done historically, the Company expects to fund the 1999 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. 24 To date, the Company has not spent significant amounts to comply with environmental or safety regulations, and it currently does not expect to do so during 1999. 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 $0.033 per common share since the Company's inception through 1996, $0.037 per common share in 1997 and $0.04 per common share in 1998. In February 1999, the Board reduced the quarterly dividend to $0.01 per common share because of the Company's current focus on debt reduction. The Company's ability to pay dividends is dependent upon available cash flow, as well as other factors. In addition, the loan agreement restricts the amount of common stock dividends to 25% of operating cash flow 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, or $1.8 million annually. Year 2000 "Year 2000," or the ability of computer systems to process dates with years beyond 1999, affects almost all companies and organizations. Computer systems that are not Year 2000 compliant by January 1, 2000 may cause material adverse effects to companies and organizations that rely upon those systems. Continuity of the Company's operations in January 2000 will not only depend upon Year 2000 compliance of the Company's computer systems and computer-controlled equipment, but also compliance of computer systems and computer-controlled equipment of third parties. These third parties include oil and natural gas purchasers and significant service providers such as electric utility companies and natural gas plant, pipeline and gathering system operators. The Company is in the process of reviewing its computer systems and computer-controlled field equipment and making the necessary modifications for Year 2000 compliance. The Company has completed modifications and testing of its primary accounting and land computer programs. The remaining computer systems have been inventoried and assessed. Remediation and testing of significant remaining systems are expected to be complete by August 1999. Some of the Company's critical field equipment, such as natural gas compressors, are partially controlled or regulated by embedded computer chips. Based on a preliminary review of all operating areas, no significant compliance exceptions have been identified. Approximately 30% of field equipment in operated areas has been inventoried. The Company expects to complete its review of the remaining 70% of field equipment inventories by April 1999. The Company plans to complete remediation and testing of identified exceptions for significant computer-controlled field equipment by August 1999. Based on its review, remediation efforts and the results of testing to date, the Company does not believe that timely modification of its computer systems and computer-controlled equipment for Year 2000 compliance represents a material risk to the Company. The Company estimates that total costs related to Year 2000 compliance efforts will be less than $500,000 of which approximately $50,000 has been incurred and expensed through December 1998. The Company has identified significant third parties whose Year 2000 compliance could affect the Company and is in the process of formally inquiring about their Year 2000 status. The Company has received responses to approximately 30% of its inquiries. Approximately 90% of respondents have indicated that they will be Year 2000 compliant by January 1, 2000. Despite its efforts to assure that such third parties are Year 2000 compliant, the Company cannot provide assurance that all significant third parties will achieve compliance in a timely manner. A third party's failure to achieve Year 2000 compliance could have a material adverse effect on the Company's operations and cash flow. The potential effect of Year 2000 non-compliance by third parties is currently unknown. The Company is currently identifying appropriate contingency plans in the event of potential problems resulting from failure of the Company's or significant third party computer systems on January 1, 2000. The Company has not completed any contingency plans to date. Specific contingency plans will be developed in response to the results of testing scheduled to be complete by August 1999, as well as the assessed probability and risk of system or equipment 25 failure. These contingency plans may include installing backup computer systems or equipment, temporarily replacing systems or equipment with manual processes, and identifying alternative suppliers, service companies and purchasers. The Company expects these plans to be complete by October 1999. New Accounting Standards The Company adopted the following pronouncements in 1998: - SFAS No. 130, "Reporting Comprehensive Income," requires that all items that are to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements, and - SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," requires reporting of financial and descriptive information about a company's reportable operating segments. The Company has identified only one operating segment, which is the exploration and production of oil and gas. The Company will be required to comply with the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" which must be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133 requires that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either offset by the change in fair value of the hedged asset or liability (if applicable) or reported as a component of other comprehensive income in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. The definition of derivatives has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. The Company primarily uses derivatives to hedge product price and interest rate risks. These derivatives are recorded at cost, and gains and losses on such derivatives are reported when the hedged transaction occurs. Accordingly, adoption of SFAS No. 133 will have an impact on the reported financial position of the Company, and although such impact has not been determined, it is currently not believed to be material. Adoption of SFAS No. 133 should have no significant impact on reported earnings, but could materially affect comprehensive income. 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, 1998, the Company's consolidated balance sheet includes a net receivable of $4.9 million for a net underproduced balancing position of 885,000 Mcf of natural gas and 7,909,000 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. Forward-Looking Statements Certain information included in this year-end report on Form 10-K and other materials filed by the Company with the Commission contain forward-looking statements relating to the Company's operations and the oil and gas industry. Such forward-looking statements are based on management's current projections and estimates and are identified by words such as "expects," "intends," "plans," "projects," "anticipates," "believes," "estimates" and similar words. 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 what is expressed or forecasted in such forward-looking statements. Among the factors that could cause actual results to differ materially are: - crude oil and natural gas price fluctuations 26 - the Company's ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling - potential delays or failure to achieve expected production from existing and future exploration and development projects - potential disruption of operations because of failure to achieve timely Year 2000 compliance by the Company or other entities with which it has material relationships, and - potential liability resulting from pending or future litigation. 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 uses derivative financial instruments for hedging purposes. 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 entirely 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 Executive Vice President of all risk management programs using derivatives and all derivative transactions. These programs are also periodically reviewed by the Board of Directors. Hypothetical changes in interest rates and prices chosen for the 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, product prices and investment market values. 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. The Company's variable rate debt was approximately $620 million at December 31, 1998. 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. During 1998, the Company entered into interest rate swap agreements that effectively convert interest rates from variable to fixed on $150 million principal through September 2005. The Company had no outstanding interest swap agreements during 1997. 27 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:
Hypothetical Change Carrying Fair in (in thousands) Amount Value Fair Value ---------- ------------- ----------- December 31, 1998 Long-term debt....... $(921,000) $(894,750) $(17,000) Interest rate swaps.. - (2,722) (8,655) December 31, 1997 Long-term debt....... (539,000) (538,288) (20,656)
In February and March 1999, the Company terminated its interest rate swaps on notional balances totaling $100 million, resulting in proceeds received and a gain of $1.1 million. This gain will be amortized against interest expense through September 2005. In February 1999, the Company sold a call option that allows the counterparty to terminate the interest rate swap in September 2001 on the remaining $50 million notional balance, resulting in proceeds received of $800,000. This amount will be deferred until the option is exercised or expires. Commodity Price Risk The Company hedges a portion of the market risks associated with its crude oil and natural gas sales. During 1998, the Company primarily entered into gas futures contracts and gas basis swap agreements to reduce exposure to price volatility in the physical markets. As of December 31, 1998, outstanding futures contracts had a fair value of a gain of $3.5 million and outstanding basis swap agreements had a fair value of a loss of $0.7 million. These futures contracts and basis swap agreements are not recorded on the Company's balance sheet. The Company did not have any significant commodity hedging activity in 1997. For these commodity derivatives that are permitted to be settled in cash or another financial instrument, sensitivity effects are as follows. At year-end 1998, the aggregate effect of a hypothetical 10% change in natural gas prices and basis would result in a $3 million change in the fair value of these financial instruments. This sensitivity does not include the effects of gas contracts that cannot be settled in cash or another financial instrument. See Note 6 to Consolidated Financial Statements. Investment in Equity Securities The Company is subject to price risk on its unhedged portfolio of publicly traded investments in equity securities of energy companies. These securities were classified as trading securities as of year-end 1998. The fair value of these securities at December 31, 1998 was $44.4 million. At year-end 1998, a 25% appreciation or depreciation in equity price would increase or decrease portfolio fair value and pre-tax earnings by approximately $11 million. As of March 1, 1999, the Company had incurred a 1999 pre-tax loss on its investment in equity securities of $8 million, of which $17.5 million was a realized loss, partially offset by a $9.5 million decrease in unrealized loss. 28 Item 8. Financial Statements and Supplementary Data The following financial statements and supplementary information are included under Item 14(a):
Page ---- Consolidated Balance Sheets......................... 31 Consolidated Statements of Operations............... 32 Consolidated Statements of Comprehensive Income..... 33 Consolidated Statements of Cash Flows............... 34 Consolidated Statements of Stockholders' Equity..... 35 Notes to Consolidated Financial Statements.......... 36 Selected Quarterly Financial Data (Note 13 to Consolidated Financial Statements)..... 55 Information about Oil and Gas Producing Activities (Note 14 to Consolidated Financial Statements)..... 55 Report of Independent Public Accountants............ 59
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, 1999. 29 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, 1998 and 1997............ 31 Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996................................... 32 Consolidated Statements of Comprehensive Income for the years ended December 31, 1998, 1997 and 1996................................... 33 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996................................... 34 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1998, 1997 and 1996................................... 35 Report of Independent Public Accountants............................. 59
2. Financial Statement Schedules: All financial schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to financial statements. 3. Exhibits: See Index to Exhibits at page 61 for a description of the exhibits filed as a part of this report. (b) Reports on Form 8-K The Company filed the following reports on Form 8-K during the quarter ended December 31, 1998 and through March 15, 1999: On December 21, 1998, the Company filed a report on Form 8-K regarding an increase in the size of its Hugoton Royalty Trust offering and termination of plans to begin royalty trust unit distribution to stockholders in 2000. On February 16, 1999, the Company filed a report on Form 8-K/A (Amendment No. 2 to Form 8-K dated April 24, 1998) to file amended financial statements for the acquisition of certain producing oil and gas properties and undeveloped acreage in the East Texas Basin from EEX Corporation. 30 CROSS TIMBERS OIL COMPANY Consolidated Balance Sheets - --------------------------------------------------------------------------------
(in thousands) December 31 ------------------------ 1998 1997 ------------ ---------- ASSETS Current Assets: Cash and cash equivalents........................................... $ 12,333 $ 3,816 Accounts receivable, net (Note 8)................................... 50,607 43,996 Investment in equity securities (Note 2)............................ 44,386 - Deferred income tax benefit (Note 5)................................ 24,816 445 Other current assets................................................ 5,436 3,905 ---------- --------- Total Current Assets.............................................. 137,578 52,162 ---------- --------- Property and Equipment, at cost -- successful efforts method (Notes 1 and 4): Producing properties................................................ 1,335,844 931,259 Undeveloped properties.............................................. 6,845 6,406 Gas gathering and other............................................. 27,829 23,703 ---------- --------- Total Property and Equipment....................................... 1,370,518 961,368 Accumulated depreciation, depletion and amortization................ (319,507) (237,532) ---------- --------- Net Property and Equipment........................................ 1,051,011 723,836 ---------- --------- Other Assets......................................................... 13,210 12,457 ---------- --------- Loans to Officers (Note 3)........................................... 5,795 - ---------- --------- TOTAL ASSETS......................................................... $1,207,594 $ 788,455 ========== ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and accrued liabilities............................ $ 93,583 $ 52,266 Payable to Royalty Trust............................................ 968 2,073 Short-term debt (Note 4)............................................ 4,962 - Accrued stock incentive compensation (Note 11)...................... 75 554 ---------- --------- Total Current Liabilities......................................... 99,588 54,893 ---------- --------- Long-term Debt (Note 4).............................................. 921,000 539,000 ---------- --------- Deferred Income Taxes Payable (Note 5)............................... 6,892 21,320 ---------- --------- Other Long-term Liabilities (Note 6)................................. 2,663 2,999 ---------- --------- Commitments and Contingencies (Note 6) Stockholders' Equity (Note 7): Series A convertible preferred stock ($.01 par value, 25,000,000 shares authorized, 1,138,729 issued, at liquidation value of $25).. 28,468 28,468 Common stock ($.01 par value, 100,000,000 shares authorized, 54,048,227 and 46,310,710 shares issued)........................... 541 463 Additional paid-in capital.......................................... 338,503 210,954 Treasury stock (9,320,971 and 6,860,779 shares)..................... (118,555) (76,656) Retained earnings (deficit)......................................... (71,506) 7,014 ---------- --------- Total Stockholders' Equity........................................ 177,451 170,243 ---------- --------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........................... $1,207,594 $ 788,455 ========== =========
See accompanying notes to consolidated financial statements. 31 CROSS TIMBERS OIL COMPANY Consolidated Statements of Operations - --------------------------------------------------------------------------------
(in thousands, except per share data) Year Ended December 31 ------------------------------- 1998 1997 1996 --------- --------- --------- REVENUES Oil and condensate....................................... $ 56,164 $ 75,223 $ 75,013 Gas and natural gas liquids.............................. 182,587 110,104 73,402 Gas gathering, processing and marketing.................. 9,438 9,851 12,032 Other.................................................... 1,297 3,094 888 --------- -------- -------- Total Revenues........................................... 249,486 198,272 161,335 --------- -------- -------- EXPENSES................................................. Production............................................... 63,148 43,580 39,365 Exploration.............................................. 8,034 2,088 - Taxes, transportation and other.......................... 29,105 16,405 11,944 Depreciation, depletion and amortization................. 83,560 47,721 37,858 Impairment (Note 1)...................................... 2,040 - - General and administrative (Note 11)..................... 13,479 15,818 16,420 Gas gathering and processing............................. 8,360 8,517 6,905 Trust development costs.................................. 1,498 665 854 --------- -------- -------- Total Expenses........................................... 209,224 134,794 113,346 --------- -------- -------- OPERATING INCOME......................................... 40,262 63,478 47,989 --------- -------- -------- OTHER INCOME (EXPENSE) Gain (loss) on investment in equity securities (Note 2).. (93,719) 1,735 (893) Interest expense, net.................................... (52,113) (26,012) (16,123) --------- -------- -------- Total Other Income (Expense)............................. (145,832) (24,277) (17,016) --------- -------- -------- INCOME (LOSS) BEFORE INCOME TAX.......................... (105,570) 39,201 30,973 Income Tax Expense (Benefit) (Note 5).................... (35,851) 13,517 10,669 --------- -------- -------- NET INCOME (LOSS)........................................ (69,719) 25,684 20,304 Preferred stock dividends................................ 1,779 1,779 514 --------- -------- -------- EARNINGS (LOSS) AVAILABLE TO COMMON STOCK................ $ (71,498) $ 23,905 $ 19,790 ========= ======== ======== EARNINGS (LOSS) PER COMMON SHARE (Notes 1 and 9) Basic................................................... $(1.65) $0.60 $0.50 ========= ======== ======== Diluted................................................. $(1.65) $0.59 $0.48 ========= ======== ======== Weighted Average Common Shares Outstanding............... 43,396 39,773 39,913 ========= ======== ========
See accompanying notes to consolidated financial statements. 32 CROSS TIMBERS OIL COMPANY Consolidated Statements of Comprehensive Income - --------------------------------------------------------------------------------
(in thousands) Year Ended December 31 ----------------------------- 1998 1997 1996 -------- ------- -------- NET INCOME (LOSS)............................................ $(69,719) $25,684 $20,304 -------- ------- ------- OTHER COMPREHENSIVE INCOME Unrealized gains on available-for-sale securities (Note 2): Unrealized holding gains................................... - 1,434 1,022 Less realized gains included in net income................. - (2,400) (56) -------- ------- ------- Other Comprehensive Income (Loss) Before Tax................. - (966) 966 Income tax benefit (expense) related to other comprehensive income.................................. - 328 (328) -------- ------- ------- Other Comprehensive Income (Loss)............................ - (638) 638 -------- ------- ------- COMPREHENSIVE INCOME (LOSS).................................. $(69,719) $25,046 $20,942 ======== ======= =======
See accompanying notes to consolidated financial statements. 33 CROSS TIMBERS OIL COMPANY Consolidated Statements of Cash Flows - --------------------------------------------------------------------------------
(in thousands) (Note 10) Year Ended December 31 --------------------------------- 1998 1997 1996 --------- --------- --------- OPERATING ACTIVITIES Net income (loss)....................................................... $ (69,719) $ 25,684 $ 20,304 Adjustments to reconcile net income (loss) to net cash.................. provided (used) by operating activities:............................... Depreciation, depletion and amortization............................. 83,560 47,721 37,858 Impairment........................................................... 2,040 - - Exploration.......................................................... 8,034 2,088 - Stock incentive compensation......................................... 1,141 3,386 (853) Deferred income tax.................................................. (35,744) 13,393 10,213 (Gain) loss from sale of properties and equity securities............. 86,628 (4,157) (576) Other non-cash items................................................. 2,540 1,864 1,317 Changes in current assets and liabilities (a)........................ (124,322) 8,027 (8,569) --------- --------- --------- Cash Provided (Used) by Operating Activities............................ (45,842) 98,006 59,694 --------- --------- --------- INVESTING ACTIVITIES Proceeds from sale of long-term investment in equity securities......... - 24,626 402 Long-term investment in equity securities............................... - (6,479) (16,093) Proceeds from sale of property and equipment............................ 2,494 17,972 37,388 Property acquisitions................................................... (296,390) (238,294) (109,535) Exploration and development costs....................................... (77,390) (90,470) (32,291) Gas plant, gathering and other additions................................ (7,517) (18,677) (4,742) Loans to officers....................................................... (5,795) - - --------- --------- --------- Cash Used by Investing Activities....................................... (384,598) (311,322) (124,871) --------- --------- --------- FINANCING ACTIVITIES Proceeds from long-term debt............................................ 877,900 688,400 188,000 Payments on long-term debt.............................................. (496,938) (437,430) (81,200) Common stock offering................................................... 133,113 - - Dividends............................................................... (8,460) (7,571) (5,339) Stock option exercises and other........................................ (269) 750 364 Purchases of treasury stock............................................. (66,389) (30,954) (34,923) --------- --------- --------- Cash Provided by Financing Activities................................... 438,957 213,195 66,902 --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........................ 8,517 (121) 1,725 Cash and Cash Equivalents, January 1.................................... 3,816 3,937 2,212 --------- --------- --------- Cash and Cash Equivalents, December 31.................................. $ 12,333 $ 3,816 $ 3,937 ========= ========= ========= (a) Changes in Current Assets and Liabilities Accounts receivable................................................. $ (7,022) $ 246 $ (16,999) Investment in equity securities (purchases net of sales)............ (131,809) - - Other current assets................................................ (1,513) (970) (1,683) Accounts payable, accrued liabilities and payable to Royalty Trust.. 16,022 8,751 10,113 --------- --------- --------- Decrease (Increase) in Current Assets and Liabilities................ $(124,322) $ 8,027 $ (8,569) ========= ========= =========
See accompanying notes to consolidated financial statements. 34 CROSS TIMBERS OIL COMPANY Consolidated Statements of Stockholders' Equity - --------------------------------------------------------------------------------
(in thousands) (Note 7) Shares Stockholders' Equity ---------------------------- --------------------------------------------------- Common Stock ------------------ Additional Retained Preferred In Preferred Common Paid-in Treasury Earnings Stock Issued Treasury Stock Stock Capital Stock (Deficit) --------- ------ -------- --------- ------ ---------- --------- -------- Balances, December 31, 1995 - 41,434 69 $ - $ 414 $156,440 $ (528) $(25,626) Issuance/vesting of performance shares...... - 168 106 - 2 2,673 (1,038) - Stock option exercises..... - 996 768 - 10 7,189 (7,931) - Treasury stock purchases... - - 2,925 - - - (30,722) - Exchange of Series A convertible preferred stock for common stock........... 1,139 (2,979) - 28,468 (30) (28,978) - - Conversion of subordinated convertible notes to common stock........... - 2,696 - - 27 27,112 - - Common stock dividends ($0.13 per share) - - - - - - - (5,242) Preferred stock dividends ($0.45 per share)....... - - - - - - - (514) Net income................. - - - - - - - 20,304 --------- ------ -------- --------- ------ ---------- --------- -------- Balances, December 31, 1996 1,139 42,315 3,868 28,468 423 164,436 (40,219) (11,078) Issuance/vesting of performance shares...... - 180 76 - 2 3,431 (1,098) - Stock option exercises..... - 924 566 - 9 8,183 (7,326) - Treasury stock purchases... - - 2,351 - - - (28,013) - Conversion of subordinated convertible notes to common stock........... - 2,892 - - 29 29,179 - - Issuance of warrants....... - - - - - 5,725 - - Common stock dividends ($0.15 per share)....... - - - - - - - (5,813) Preferred stock dividends ($1.56 per share)....... - - - - - - - (1,779) Net income................. - - - - - - - 25,684 --------- ------ -------- --------- ------ ---------- --------- -------- Balances, December 31, 1997 1,139 46,311 6,861 28,468 463 210,954 (76,656) 7,014 Sale of common stock....... - 7,203 - - 72 133,041 - - Issuance/vesting of performance shares........ - 82 27 - 1 1,804 (536) - Stock option exercises..... - 452 25 - 5 2,986 (483) - Treasury stock purchases... - - 4,330 - - - (65,575) - Treasury stock issued...... - - (1,922) - - (10,282) 24,695 - Common stock dividends ($0.16 per share)....... - - - - - - - (7,022) Preferred stock dividends ($1.56 per share)....... - - - - - - - (1,779) Net loss................... - - - - - - - (69,719) --------- ------ -------- --------- ------ ---------- --------- -------- Balances, December 31, 1998 1,139 54,048 9,321 $ 28,468 $ 541 $ 338,503 $(118,555) $(71,506) ========= ====== ======== ========= ====== ========== ========= ========
See accompanying notes to consolidated financial statements. 35 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 March 19, 1997 and February 25, 1998 (Note 7). The Company is an independent oil and gas company with production and exploration concentrated in Texas, Oklahoma, Kansas, New Mexico, Wyoming and Alaska. The Company also gathers, processes and markets gas, transports and markets oil and conducts other activities directly related to the oil and gas producing industry. 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, although the Company increased its exploration activities in 1997 and 1998. 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 $15,859,000 at December 31, 1998 and $26,570,000 at December 31, 1997, related to wells in progress 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. Effective October 1, 1995, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of. When impairment review is necessary, the carrying value of property, plant and equipment intended to be retained 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 reserve and production information and pricing assumptions that management believes are reasonable. Generally, for producing properties, the review considers proved reserves, though probable reserves and other conditions are considered if warranted. 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. 36 Cross Timbers Royalty Trust The Company makes monthly net profits payments to Cross Timbers Royalty Trust based on revenues and costs related to properties from which net profits interests were carved. Net profits payments to the Cross Timbers Royalty Trust are generally based on revenues received and costs disbursed by the Company in the prior month. For financial reporting purposes, the Company reduces oil and gas revenues and taxes on production for amounts allocated to the Cross Timbers Royalty Trust. The Cross Timbers Royalty Trust's portion of development costs are expensed as trust development costs in the accompanying consolidated statements of operations. The Company owned approximately 22% of the Cross Timbers Royalty Trust publicly traded units at December 31, 1998 and 1997. Cross Timbers Royalty Trust units are traded on the New York Stock Exchange under the symbol "CRT." Hugoton Royalty Trust In December 1998, the Company formed the Hugoton Royalty Trust by conveying an 80% net profits interest in properties that are principally located in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These properties represent approximately 30% of the Company's existing reserve base. The Company filed a registration statement with the Securities and Exchange Commission ("Commission") in December 1998 and plans to offer approximately 40% of the trust units to the public in March or April 1999. The trust units will be listed on the New York Stock Exchange under the symbol "HGT." 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 No. 115, Accounting for Certain Investments in Debt and Equity Securities, equity securities acquired during 1998 have been recorded as trading securities since such securities were acquired principally for resale in the near future. Accordingly, such investment at December 31, 1998 has been recorded as a current asset at market value, unrealized holding gains and losses have been recognized in the consolidated statement of operations, and cash flows from purchases and sales of equity securities have been included in cash provided (used) by operating activities in the consolidated statement of cash flows. Gains (losses) on trading securities and interest related to the cost of these investments have been classified as other income (expense). Such gains (losses) were previously classified as other revenue and interest related to such investments was previously classified as interest expense. Prior to 1998, the Company's investments in equity securities were recorded as available-for-sale securities. As a result, such investments were recorded as long-term assets at market value, unrealized holding gains and losses were recorded as a separate component of stockholders' equity and cash flows from purchases and sales of equity securities were included in cash provided (used) by investing activities. See Note 2. Other Assets Other assets primarily include deferred debt costs that are amortized over the term of the related debt (Note 4). Other assets are presented net of accumulated amortization of $4,697,000 at December 31, 1998 and $2,860,000 at December 31, 1997. Derivatives The Company uses derivatives on a limited basis to hedge interest rate and product price risks, as opposed to their use for trading purposes. Amounts receivable or payable under interest swap agreements are recorded as adjustments to interest expense. Gains and losses on commodity futures contracts and other price risk management instruments are recognized in oil and gas revenues when the hedged transaction occurs. Cash flows related to derivative transactions are included in operating activities. See Note 8. 37 Production Imbalances 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, 1998, the Company recorded a net receivable of $4,904,000 for a net underproduced balancing position of 885,000 Mcf of natural gas and 7,909,000 Mcf of carbon dioxide. At December 31, 1997, the Company recorded a net receivable of $5,054,000 for a net underproduced balancing position of 1,114,000 Mcf of natural gas and 8,049,000 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 $56.3 million for 1998, $57.1 million for 1997 and $56.4 million for 1996. These amounts are net of intercompany eliminations. Other Revenues Other revenues include gains and losses from sale of property and equipment. The Company realized gains on sale of property and equipment of $795,000 in 1998, $1,757,000 in 1997 and $520,000 in 1996. Exploration Expense During 1998, the Company incurred $8 million of exploration costs, primarily composed of geological and geophysical costs related to the 1998 exploration program. Exploration costs were $2.1 million in 1997. Interest Expense Interest expense includes amortization of deferred debt costs and is presented net of interest income of $91,000 in 1998, $71,000 in 1997 and $152,000 in 1996, and net of capitalized interest of $1,070,000 in 1998 and $1,185,000 in 1997. No interest was capitalized in 1996. 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 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, based on the market price of the Company's common stock. 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 11. Earnings per Common Share Effective December 31, 1997, the Company adopted SFAS No. 128, Earnings Per Share, which changed the method of computing and disclosing earnings per share for all periods. Under SFAS No. 128, the Company must report 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. The Company previously only reported earnings per share excluding potentially dilutive securities because their effect was antidilutive or less than 3% dilutive, as prescribed by the accounting pronouncement superseded by SFAS No. 128. See Note 9. Earnings (loss) per common share for all periods presented is based on weighted average common shares outstanding as adjusted for the three-for-two stock splits on March 19, 1997 and February 25, 1998 (Note 7). 38 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 1998. In 1997, gas sales to one purchaser were approximately 14% of total revenues. In 1996, gas sales to two purchasers were approximately 15% and 14% of total revenues. Recent Accounting Pronouncements In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which is required to be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133 requires that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either a) offset by the change in fair value of the hedged asset or liability (if applicable) or b) reported as a component of other comprehensive income in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. The definition of derivatives has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. The Company primarily uses derivatives to hedge product price and interest rate risks. Such derivatives are reported at cost, if any, and gains and losses on such derivatives are reported when the hedged transaction occurs. Accordingly, the Company's adoption of SFAS No. 133 will have an impact of the reported financial position of the Company, and although such impact has not been determined, it is currently not believed to be material. Adoption of SFAS No. 133 should have no significant impact on reported earnings, but could materially affect comprehensive income. 2. Investment in Equity Securities The Company periodically invests in publicly traded equity securities of select energy companies which it believes to be undervalued. Since classified as trading securities, this investment at December 31, 1998 is recorded as a current asset at market value. Realized gains and losses are computed based on a first-in, first-out determination of cost of securities sold. After sale of its current investment, the Company does not plan to make future investments in equity securities of other energy companies. The following are components of gain (loss) on investment in equity securities (in thousands):
1998 1997 1996 --------- ------- ------ Realized gains (losses) on sale of securities: Gains............................................ $ 887 $2,400 $ 56 Losses........................................... (15,706) - - -------- ------ ----- Net gains (losses)............................... (14,819) 2,400 56 Unrealized gains (losses) (a)...................... (72,605) - - Interest expense related to investment in equity securities................................ (6,295) (665) (949) -------- ------ ----- Gains (losses) on investment in equity securities.. $(93,719) $1,735 $(893) ======== ====== =====
(a) Because investments in equity securities were recorded as available- for-sale securities prior to 1998, unrealized gains and losses for 1997 and 1996 are reported as a component of stockholders' equity, as shown in the Consolidated Statements of Comprehensive Income. As of March 1, 1999 the Company had incurred a 1999 pre-tax loss on its investment in equity securities of $8 million, of which $17.5 million was a realized loss, partially offset by a $9.5 million decrease in unrealized loss. 39 3. Related Party Transactions Loans to Officers Pursuant to margin support agreements with each of six officers, the Company agreed to use the value of its investments in equity securities (Note 2) to provide margin support for the officers' broker accounts in which they held Company common stock. In August 1998, the Board of Directors authorized these agreements so that the officers would not be forced to sell Company common stock, particularly at depressed prices, potentially creating further downward pressure on the stock price. These agreements provide that each officer cannot purchase additional securities in his broker account, or engage in any transaction that would increase the margin requirements for his account, including withdrawal of any funds or securities. The Company also has 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. In January and February 1999, an additional $430,000 was loaned. These loans are full recourse and due in five years, with interest equal to the Company's bank debt rates (Note 4). Total officer margin debt on their broker accounts at March 1, 1999 was $11.2 million. Other Transactions A director-related company performed consulting services in 1998 in connection with the Cook Inlet Acquisition (Note 12). 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 interest conveyed from the Company's 100% working interest in these properties. In 1997, the Company paid fees of $1.6 million to this director-related company in connection with property sales and the Amoco Acquisition. These consulting fees are effectively capitalized as a portion of property cost. 4. Debt The Company's outstanding debt consists of the following (in thousands):
December 31 ------------------- 1998 1997 -------- --------- Short-term Debt: Short-term borrowings, 7.4% at December 31, 1998................... $ 4,962 $ 10,000 Reclassified to long-term debt..................................... - (10,000) -------- -------- Total short-term debt.............................................. $ 4,962 $ - ======== ======== Long-term Debt: Senior debt- Bank debt under revolving credit agreements due June 30, 2003, 6.9% at December 31, 1998....................................... $615,000 $229,000 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 Other long-term debt............................................... 6,000 - -------- -------- Sub-total long-term debt........................................... 921,000 529,000 Reclassified from short-term debt.................................. - 10,000 -------- -------- Total long-term debt............................................... $921,000 $539,000 ======== ========
40 Senior Debt On November 16, 1998, the Company entered into a new Revolving Credit Agreement with commercial banks ("loan agreement"). As of December 31, 1998, the loan agreement had a borrowing base and commitment of $615 million with no unused borrowing capacity. 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. Otherwise, borrowings under the loan agreement do not mature until June 30, 2003, 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. The borrowing base is scheduled to be redetermined in June 1999. Based on year-end proved reserves, the Company does not expect a reduction in the borrowing base upon its redetermination. Reclassification of short-term to long-term debt at December 31, 1997 represents unused capacity under the loan agreement based on outstanding debt balances at that date. 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 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, 1998 were based on LIBOR rates with a maturity of one to six months and accrued at the applicable LIBOR rate plus 1 3/8%. 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 of 3/8% on unused borrowing commitments. The weighted average interest rate on senior debt was 6.9% during 1998 and 1997 and 6.7% during 1996. See Note 8 regarding interest rate swap agreements. Subordinated Debt The Company sold $125 million of 9 1/4% senior subordinated notes ("9 1/4% Notes") on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes ("8 3/4% Notes") on October 28, 1997 (the 9 1/4% Notes and the 8 3/4% Notes collectively referred to as "the Notes"). 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. In addition, on or prior to April 1, 2000 for the 9 1/4% Notes and November 1, 2000 for the 8 3/4% Notes, the Company may redeem up to one-third of the Notes with the net proceeds from one or more public equity offerings at a price of approximately 109% plus accrued interest, subject to certain requirements. Upon a change in control of the Company, the holders of the Notes 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. To reduce the interest rate on a portion of its subordinated debt, the Company has entered an agreement with a bank that has purchased on the market 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 change in market value of the Notes from the date purchased by the bank is payable to or receivable from the bank. The Company funded market value depreciation of $169,000 in January 41 1999. The Company has the option of repurchasing the Notes from the bank at any time at market value. Other Debt As part of the Cook Inlet Acquisition, the Company executed a $6 million non-interest bearing promissory note payable to Shell. Payments of $3 million, $2 million and $1 million are due when the average NYMEX crude oil price for 60 consecutive calendar days equals or exceeds $18.50, $19.50 and $20.50, respectively. See also Note 7 "- Registration Statement." 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):
1998 1997 1996 -------- -------- -------- Income tax expense (benefit) at the federal statutory rate of 34%............................................. $(35,893) $13,329 $10,531 State and local taxes and other............................................ 42 188 138 -------- ------- ------- Income tax expense (benefit)............................................... $(35,851) $13,517 $10,669 ======== ======= =======
Components of income tax expense (benefit) are as follows (in thousands):
1998 1997 1996 -------- -------- -------- Current income tax......................................................... $ (107) $ 124 $ 456 Deferred income tax expense (benefit)...................................... (2,626) 22,509 13,152 Net operating loss carryforward............................................ (33,118) (9,116) (2,939) -------- ------- ------- Income tax expense (benefit)............................................... $(35,851) $13,517 $10,669 ======== ======= =======
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 $24,816,000 and a long-term liability of $6,892,000 at December 31, 1998, and a current asset of $445,000 and a long-term liability of $21,320,000 at December 31, 1997. Significant components of net deferred tax assets and liabilities are (in thousands):
December 31 ------------------ 1998 1997 ------- --------- Deferred tax assets: Net operating loss carryforwards......................................... $54,044 $ 20,926 Trust development expenses............................................... 4,454 3,959 Accrued stock appreciation right and performance share compensation...... 576 739 Unrealized loss on trading securities.................................... 24,686 - Other.................................................................... 2,626 1,593 ------- -------- Total deferred tax assets......................................... 86,386 27,217 ------- -------- Deferred tax liabilities: Intangible development costs............................................. 48,913 37,856 Tax depletion and depreciation in excess of financial statement amounts.. 16,894 8,008 Other.................................................................... 2,655 2,228 ------- -------- Total deferred tax liabilities.................................... 68,462 48,092 ------- -------- Net deferred tax assets (liabilities)...................................... $17,924 $(20,875) ======= ========
As of December 31, 1998, the Company has estimated tax loss carryforwards of approximately $160 million, of which $10 million are related to capital losses. The capital loss tax carryforwards expire in 2003 while the remaining $150 million are scheduled to expire in 2008 through 2013. The Company believes it will be able to realize its deferred 42 tax asset, as it plans to utilize its tax loss carryforwards through gains generated from the sale of Hugoton Royalty Trust units and non-strategic asset sales which are to begin in 1999. 6. Commitments and Contingencies Leases The Company leases offices, vehicles and certain other equipment in its primary locations under non-cancelable operating leases. As of December 31, 1998, minimum future lease payments for all non-cancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows (in thousands): 1999....................................... $ 7,528 2000....................................... 7,177 2001....................................... 6,968 2002....................................... 6,886 2003....................................... 6,858 Remaining.................................. 6,548 ------- Total...................................... $41,965 =======
Amounts incurred by the Company under operating leases (including renewable monthly leases) were $11,180,000 in 1998, $9,132,000 in 1997 and $5,489,000 in 1996. 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. 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. This transaction has been recorded as a sale and operating leaseback, with no gain or loss on the sale. Proceeds of the sale were used to reduce bank debt. 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 (Note 4) and may be irrevocably fixed by the Company with 20 days advance notice. As of December 31, 1998, annual rentals were $1.7 million. 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. This transaction has been 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 balance sheet. Proceeds of the sale were used to reduce bank debt. Employment Agreements Two executive officers have entered into 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, each of the officers receives a minimum annual salary of $300,000 and is 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 officer will receive severance pay equal to the amount that would have been paid under the agreement had it not been terminated. If such termination follows a change in control of the Company, the officer is entitled to a lump-sum payment of three times his most recent annual compensation. 43 Gas Sales Contracts The Company has entered into 1999 futures contracts to sell 175,000 Mcf per day in April at $1.98 per Mcf, 160,000 Mcf per day in May and June at $1.96 per Mcf, 40,000 Mcf per day in July at $2.00 per Mcf, 50,000 Mcf per day in August and September at $2.04 per Mcf and 30,000 Mcf per day in October through December at an average of $2.13 per Mcf. Prices to be realized for hedged production may be less than these hedged prices because of location, quality and other adjustments. The Company has entered into basis swap agreements that effectively fix the San Juan Basin basis at $0.25 per Mcf for 30,000 Mcf per day for April and May 1999 and 20,000 Mcf per day from June through December 1999, and $0.28 per Mcf for 10,000 Mcf per day from January through December 2000. The Company has basis swap agreements that effectively fix the Wyoming basis at $0.27 per Mcf for 15,000 Mcf per day for April 1999 and 10,000 Mcf per day from May through December 1999. The Company also has basis swap agreements that effectively fix Oklahoma basis at $0.13 per Mcf for 10,000 Mcf per day for April 1999 through December 1999. The Company's termination of futures contracts related to first quarter 1999 gas production, net of the effects of basis swap agreements, resulted in a net gain of $6.4 million. This gain will be recognized as additional gas revenue of approximately $0.25 per Mcf in the first quarter of 1999. The Company has committed a minimum gas sales price of $2.00 per Mcf for gas sales related to April 1999 through March 2000 distributions of the Hugoton Royalty Trust. The Company plans to sell approximately 40% of Hugoton Royalty Trust units to the public in March or April 1999. The underlying volumes for units to be sold to the public are approximately 36,000 Mcf per day. Under the terms of its amended purchase and sale agreement with Shell for the Cook Inlet Acquisition (Note 12), the Company has committed to sell to Shell 20,000 Mcf of gas per day from March 1, 1999 through 2003 in the San Juan Basin with an estimated basis differential of $0.24 per Mcf. The Company has also agreed to sell Shell in East Texas daily gas volumes of 22,000 Mcf in 1999, 20,000 Mcf in 2000, 17,500 Mcf in 2001, 16,500 Mcf in 2002 and 15,000 Mcf in 2003 at the index price less a weighted average transportation fee of $0.24 per Mcf. The Company has committed to sell all gas production from certain properties in the East Texas Basin Acquisition 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. 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 has 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 contract price of approximately 10% of the month's average NYMEX futures contract for West Texas Intermediate crude oil, adjusted for point of physical delivery. Section 29 Tax Credits The Company has entered contracts to monetize Section 29 tax credits generated by production from qualified properties, most of which were acquired in December 1997. As a result, the Company received approximately $2.9 million in 1998 and anticipates receiving approximately $2.8 million annually from 1999 through 2002 which will be recorded as gas revenue. 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 arms-length transactions, which actions reduced the royalties paid to the plaintiffs and those similarly situated, and that 44 such actions are a breach of the leases under which the royalties are paid. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. The Company filed motions to dismiss the action due to lack of proper venue, which motions were denied. The decision denying the motions is being appealed. 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 Company was not made aware of the claim until the U.S. Justice Department contacted the Company in August 1998. 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 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 Company has not been served with this complaint that is under review by the U.S. Justice Department. The Company has filed a response with the U.S. Justice Department and is awaiting its decision whether to intervene in the case. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. 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, liquidity or operations. 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 Notes 3 and 12. 7. Equity Three-for-Two Stock Split The Company effected a three-for-two common stock split on February 25, 1998 and March 19, 1997. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits. Common Stock On April 27, 1998, the Company completed a public offering of 7,500,000 shares of common stock, of which 7,203,450 shares were sold by the Company and 296,550 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 that closed on April 24, 1998 (Note 12). The offering was made pursuant to the shelf registration statement filed with the Commission in February 1998. See "-Registration Statement" below. On September 30, 1998, the Company issued from treasury 1,921,850 shares to Shell Western E&P, Inc., Shell Deepwater Development Holdings, Inc., and Shell Offshore Inc. ("Shell") for the Cook Inlet Acquisition (Note 12). As of December 31, 1998, these shares are valued at $7.50 per share, or a total of $14.4 million. The Company effectively guaranteed Shell a $20 per share value, resulting in an accrued liability of $12.50 per share, or a total of $24 million, that is included in accounts payable and accrued liabilities in the accompanying consolidated balance sheet at December 31, 1998. 45 Performance Shares The Company issued performance shares totaling 82,125 shares in 1998, 180,000 shares in 1997 and 167,625 shares in 1996 (Note 11). Treasury Stock The Company's treasury share acquisitions totaled 4,373,138 shares in 1998 at an average cost of $15.19 per share, 2,571,396 shares in 1997 at an average cost of $12.06 per share and 3,341,515 shares in 1996 at an average cost of $10.45 per share. Additionally, the Company received 8,904 shares in 1998, 421,212 shares in 1997 and 457,994 shares in 1996 that are held in treasury, as payment for the option price upon exercise of stock options. Shareholder Rights Plan On August 25, 1998, the Board of Directors adopted a shareholder rights plan that is designed to assure that all shareholders 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 ("Right") was declared for each outstanding share of common stock, par value $.01 per share, payable on September 15, 1998 to shareholders of record on that date. Each Right entitles shareholders 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. Registration Statement In February 1998, the Company filed a shelf registration statement with the Commission to potentially offer securities which may include debt securities, preferred stock, common stock or warrants to purchase debt securities, preferred stock or common stock. The shelf registration statement was amended on April 8, 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 will be used for general corporate purposes, including reduction of bank debt. After the April 1998 common stock offering, $253.8 million remains available under the shelf registration statement for future sales of securities. Common Stock Warrants As partial consideration for producing properties acquired in December 1997 (Note 12), the Company issued warrants to purchase 937,500 shares of common stock at a price of $15.31 per share for a period of five years. These warrants were valued at $5,725,000 and recorded as additional paid-in capital. Common Stock Dividends Since the Company's inception, the Board of Directors has declared quarterly dividends of $0.033 per common share through 1996, $0.037 per common share in 1997 and $0.04 per common share in 1998. In February 1999, the quarterly dividend was reduced to $0.01 per common share in response to the low commodity price environment and the Company's 1999 goal to reduce debt by $300 million. See Note 4 regarding restrictions on dividends. Series A Convertible Preferred Stock In September 1996, pursuant to the Company's exchange offer, a total of 2,979,249 shares of common stock were exchanged for 1,138,729 shares of Series A convertible preferred stock ("Preferred Stock"). The Company incurred costs of $540,000 related to this exchange offer. All exchanged shares of common stock have been canceled and are authorized but unissued. Preferred Stock is recorded in the accompanying consolidated balance sheet 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 after October 15, 1999. Redemption is allowed only 46 under certain circumstances on or before October 15, 2000 at $26.09 per share, and thereafter unconditionally at prices declining ratably annually to $25.00 per share after October 15, 2006, plus dividends accrued and unpaid to the redemption date. 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 2.16 shares of common stock for each share of Preferred Stock, subject to adjustment in certain events. Preferred Stock holders are allowed one vote for each common share into which their Preferred Stock may be converted. Convertible Debt During November and December 1996, $27.7 million principal of the Company's 5 1/4% convertible subordinated notes (Note 4) was converted by noteholders into 2,696,521 shares of common stock. In January 1997, principal of $29.7 million of the notes was converted by noteholders into 2,892,363 shares of common stock. 8. Financial Instruments The Company uses financial and commodity-based derivative contracts to manage exposures to interest rate and commodity price 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, basis swaps and option agreements to hedge its exposure to price fluctuations on crude oil and natural gas sales. During 1998, the Company recognized net gains of $7.7 million primarily related to futures contracts and basis swap transactions. This gain is recorded as a component of natural gas sales. The Company did not have significant commodity hedging activity during 1997 or 1996. See Note 6. 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. Settlements of net amounts due are made quarterly, based on LIBOR rates (Note 4), which is the same interest rate basis as the Company's senior debt borrowings. In February and March 1999, the Company terminated its interest rate swaps on notional balances totaling $100 million, resulting in proceeds received and a gain of $1.1 million. This gain will be amortized against interest expense through September 2005. In February 1999, the Company sold a call option that allows the counterparty to terminate the interest rate swap in September 2001 on the remaining $50 million notional balance, resulting in proceeds received of $800,000. This amount will be deferred until the option is exercised or expires. 47 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, 1998 and 1997. The following are estimated fair values and carrying values of the Company's other financial instruments at each of these dates (in thousands):
Asset (Liability) ---------------------------------------------- December 31, 1998 December 31, 1997 ---------------------- ---------- ---------- Carrying Fair Carrying Fair Amount Value Amount Value ---------- ---------- ---------- ---------- Investment in equity securities.. $ 44,386 $ 44,386 $ - $ - Short-term debt.................. (4,962) (4,962) - - Long-term debt................... (921,000) (894,750) (539,000) (538,288) Futures contracts................ - 3,525 - - Basis swap agreements............ - (690) - - Interest rate swap agreements.... - (2,722) - -
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 notes is based on a current market quote, while other long-term debt is based on the estimated present value of expected cash flows. The fair value of all other financial instruments is based on current market quotes. 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 $375,000 at December 31, 1998 and $911,000 at December 31, 1997. 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 these contracts are placed with major banks and financial institutions. 48 9. 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 -------- -------- --------- 1998 - ------------------------------------------------------ Basic Net loss....................................... $(69,719) Preferred stock dividends...................... (1,779) -------- Loss available to common stock - basic......... (71,498) 43,396 $(1.65) ========= Diluted Effect of dilutive securities (a): Stock options................................ - 338 Warrants..................................... - 23 -------- ------ Loss available to common stock-diluted......... $(71,498) 43,757 $ (1.65)(b) ======== ======== ========= 1997 - ------------------------------------------------------ Basic Net income..................................... $ 25,684 Preferred stock dividends...................... (1,779) -------- Earnings available to common stock - basic..... 23,905 39,773 $ 0.60 ========= Diluted Effect of dilutive securities: Stock options.......................... - 451 Warrants............................... - 3 5 1/4% convertible subordinated notes.. 46 115 -------- -------- Earnings available to common stock - diluted... $ 23,951 40,342 $ 0.59 ======== ======== ========= 1996 - ------------------------------------------------------ Basic Net income..................................... $ 20,304 Preferred stock dividends...................... (514) -------- Earnings available to common stock - basic..... 19,790 39,913 $ 0.50 ========= Diluted Effect of dilutive securities: Stock options.......................... - 361 5 1/4% convertible subordinated notes.. 2,570 6,039 -------- -------- Earnings available to common stock - diluted... $ 22,360 46,313 $ 0.48 ======== ======== =========
(a) Based on common shares outstanding at December 31, 1998, potential conversion of Series A convertible preferred stock becomes dilutive to earnings per share when annual earnings available to common stock exceeds approximately $32.4 million and when quarterly earnings available to common stock exceeds approximately $8.1 million. (b) Because of the antidilutive effect of dilutive securities on loss per common share, diluted loss available to common stock is the same as basic. 49 10. Supplemental Cash Flow Information The consolidated statements of cash flows exclude the following non-cash transactions : - The Cook Inlet Acquisition on September 30, 1998 (Note 12), a purchase of oil-producing properties for 1,921,850 shares of common stock, a related effective guarantee of $20 per share value (Note 7) and a $6 million note payable (Note 4) - Issuance of warrants in 1997 to purchase 937,500 shares of common stock and exchange of properties valued at $15.7 million, as partial consideration for producing properties acquired - Grants of performance shares of 82,125 in 1998, 180,000 in 1997 and 167,625 in 1996 to key employees and nonemployee directors (Note 11) - Vesting of performance shares of 81,000 in 1998 and 243,000 performance shares in 1997 - Receipt of common stock of 8,904 shares (valued at $181,000) in 1998, 421,212 shares (valued at $5,430,000) in 1997 and 457,994 shares (valued at $4,768,000) in 1996 for the option price of exercised stock options - Conversion of 5 1/4% convertible subordinated notes of $29.7 million principal amount into 2,892,363 shares of common stock in 1997 and $27.7 million principal amount into 2,696,521 shares of common stock in 1996 - Exchange of 2,979,249 shares of common stock for 1,138,729 shares of Series A convertible preferred stock in 1996 Interest payments during 1998 totaled $57,200,000, including $1,070,000 of capitalized interest. Interest payments totaled $21,276,000 in 1997 and $16,369,000 in 1996. Income tax payments were $941,000 in 1997 and $6,000 in 1996; during 1998, net income tax refunds were $454,000. 11. 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% after three years of service. All employees over 21 years of age and with at least three months service with the Company may participate. Company contributions under the plan were $1,766,000 in 1998, $1,180,000 in 1997 and $979,000 in 1996. 1991 Stock Incentive Plan A total of 1,012,500 incentive units ("Units"), have been granted to directors, officers and other key employees under the 1991 Stock Incentive Plan ("1991 Plan"). Units consist of a stock option ("Option") and a stock appreciation right ("SAR"). An Option provides the right to purchase one share of common stock at the exercise price, which generally is the market price at the date the Unit is granted. A SAR entitles the recipient to a payment equal to twice the excess of the market price of one share of common stock on the date the Option is exercised over the exercise price. As of December 31, 1998, 3,341 Units remain available for grant under the 1991 Plan. General and administrative expense includes a reduction of stock incentive compensation related to SARs of $299,000 in 1998, and stock incentive compensation expense of $359,000 in 1997 and $3.7 million in 1996. SAR cash payments were $180,000 in 1998, $288,000 in 1997 and $7.1 million in 1996. 50 1994 and 1997 Stock Incentive Plans Under the 1994 Stock Incentive Plan ("1994 Plan") and the 1997 Stock Incentive Plan ("1997 Plan"), a total of 2,250,000 shares of common stock may be issued under each plan to directors, officers and other key employees pursuant to grants of Options or performance shares of common stock ("performance shares"). At December 31, 1998, 25,177 shares remained available for grant under the 1994 Plan and 102,624 shares remained 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 are not exercisable prior to six months and no Option is exercisable after ten years from its 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. As of December 31, 1998, there are 356,250 outstanding stock options under the 1997 Plan that vest when the common stock price reaches $25. 1998 Stock Incentive Plan In May 1998, the stockholders approved the 1998 Stock Incentive Plan ("1998 Plan") under which 6 million 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. During 1998, 675,750 stock options were granted under the 1998 Plan. Additionally, 810,375 stock options were designated to be granted to specific optionees upon each of their exercises of all outstanding vested options granted under the 1997 Plan. Stock options will vest and become exercisable annually in equal amounts over a five-year period, with provision for accelerated vesting of half the options when the common stock price first closes at or above $25, and of the remainder when the common stock price first closes at or above $30. 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 72,000 in 1998, 169,875 in 1997 and 154,125 in 1996, of which 81,000 vested in 1998 and 243,000 vested in 1997 when the common stock price reached specified levels. General and administrative expense includes compensation related to these performance share grants of $1.6 million in 1998, $3.3 million in 1997 and $2.5 million in 1996. As of December 31, 1998, there are 72,000 performance shares that vest when the common stock price reaches $22.50. The Company also issued to nonemployee directors a total of 10,125 performance shares in each of 1998 and 1997 and 13,500 performance shares in 1996, which vested upon grant. Royalty Trust Option Plan In May 1998, the stockholders approved the 1998 Royalty Trust Option Plan ("Option Plan"). Under the terms of the Option Plan, the Company may grant to key employees options to purchase units of beneficial interest in one or more royalty trusts that may be established by the Company. Such options will allow the purchase of royalty trust units at fair market value on the date of grant in an aggregate amount not to exceed $12 million. In December 1998, the Company granted options to purchase Hugoton Royalty Trust units at a total price of $12 million, subject to completion of the initial public offering of the Hugoton Royalty Trust within six months of the date of grant. The options will be priced at the initial public offering price. 51 Unit/ Option Activity and Balances The following summarizes Unit and Option activity and balances from 1996 through 1998: 1994, 1997 Weighted and Average 1991 Plan 1998 Plans Exercise Incentive Stock Price Units Options ------- --------- ---------- 1996 - -------------------------------------- Beginning of year........... $ 6.27 835,810 1,399,250 Grants................. 9.64 - 303,750 Exercises.............. 5.70 (784,658) (211,079) Forfeitures............ 6.61 (189) (4,925) -------- ---------- End of year................. 7.32 50,963 1,486,996 ======== ========== Exercisable at end of year.. 6.66 50,963 1,006,146 ======== ========== 1997 - -------------------------------------- Beginning of year........... $ 7.32 50,963 1,486,996 Grants................. 12.11 - 1,757,250 Exercises.............. 6.75 (26,213) (897,234) Forfeitures............ 8.79 - (18,315) -------- ---------- End of year................. 11.11 24,750 2,328,697 ======== ========== Exercisable at end of year.. 10.96 24,750 1,119,044 ======== ========== 1998 - -------------------------------------- Beginning of year........... $11.11 24,750 2,328,697 Grants................. 17.52 - 1,395,750 Exercises.............. 11.64 (6,750) (1,081,711) Forfeitures............ 17.19 - (21,750) -------- ---------- End of year................. 14.23 18,000 2,620,986 ======== ========== Exercisable at end of year.. 11.03 18,000 1,351,236 ======== ========== The following summarizes information about Units/ Options at December 31, 1998:
Units/ Options Outstanding Units/ Options Exercisable ------------------------------- -------------------------- Weighted Weighted Weighted Average Average Average Range of Remaining Exercise Exercise Exercise Prices Number Term Price Number Price --------------- --------- --------- -------- --------- -------- 1991 Plan $5.32-$7.56 18,000 3.1 years $ 5.43 18,000 $ 5.43 1994, 1997 and 1998 Plans $6.61-$7.89 235,015 6.5 years 7.23 235,015 7.23 $9.67-$10.92 264,971 7.4 years 9.68 264,971 9.68 $12.04-$13.40 762,500 8.4 years 12.27 747,000 12.21 $15.53-$18.22 1,358,500 9.4 years 17.58 104,250 15.54 --------- --------- 2,638,986 1,369,236 ========= =========
52 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 $6.82 in 1998, $5.05 in 1997 and $3.82 in 1996.
1998 1997 1996 -------- -------- -------- Risk-free interest rates......... 5.6% 6.4% 6.4% Dividend yield................... 3.2% 1.6% 1.4% Weighted average expected lives.. 5 years 5 years 6 years Volatility....................... 52% 47% 35%
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 1998, 1997 and 1996, 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 (Note 1):
(in thousands, except per share data) 1998 1997 1996 -------- ------- ------- Earnings (loss) available to common stock: As reported............................... $(71,498) $23,905 $19,790 Pro forma................................. $(75,785) $21,646 $19,767 Earnings (loss) per common share: Basic As reported...................... $ (1.65) $ 0.60 $ 0.50 Pro forma........................ $ (1.75) $ 0.54 $ 0.50 Diluted As reported...................... $ (1.65) $ 0.59 $ 0.48 Pro forma........................ $ (1.75) $ 0.54 $ 0.48
12. Acquisitions On May 14, 1997, the Company acquired primarily gas-producing properties in Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39 million from a subsidiary of Burlington Resources Inc. The properties are primarily operated interests. The Company funded the acquisition with bank debt and cash flow from operations. On December 1, 1997, the Company acquired interests in certain producing oil and gas properties in the San Juan Basin of New Mexico ("Amoco Acquisition") from a subsidiary of Amoco Corporation ("Amoco") for $252 million, including warrants to purchase 937,500 shares of the Company's common stock at a price of $15.31 per share for a period of five years. After adjustments for other acquisition costs, estimated cash flows through date of closing and preferential purchase rights exercised by third parties, the properties were purchased for approximately $195 million, including approximately $5.7 million value for the warrants. Amoco elected to accept certain producing properties owned by the Company valued at $15.7 million in lieu of cash, reducing cash consideration to $173.6 million, which was funded with bank debt. Additional purchase price revisions may result from post-closing adjustments. On April 24, 1998, the Company acquired producing properties in the East Texas Basin from EEX Corporation ("East Texas Basin Acquisition") for $265 million. After purchase price adjustments primarily resulting from net revenues from the January 1, 1998 effective date through April 24, 1998, the properties were purchased for an estimated price of $245 million. In connection with the acquisition, the Company sold a production payment to EEX Corporation for $30 million. The production payment is payable from production from certain properties acquired in the East Texas Basin Acquisition during the 10-year period beginning January 1, 2002. EEX Corporation effectively pays all taxes, royalties and production expenses related to such production. The Company has the option to repurchase a portion of this production payment each December, beginning in 1998; this option was not exercised in December 1998. The cost of the East Texas Basin Acquisition (net of the production payment sold) of $215 million was funded by bank borrowings 53 which were partially repaid by proceeds from the sale of common stock (Note 7). Purchase price revisions may result from post-closing adjustments. On September 30, 1998, the Company acquired oil-producing properties in the Middle Ground Shoal Field of Alaska's Cook Inlet ("Cook Inlet Acquisition") from various Shell Oil Company affiliates ("Shell"). The acquired interests include a 100% working interest in two State of Alaska leases, two offshore production platforms and a 50% interest in certain operated production pipelines and onshore processing facilities. The acquisition had an effective date of July 1, 1998, and is subject to customary post-closing adjustments. The Company acquired the properties in exchange for 1,921,850 shares of the Company's common stock. These shares are subject to a contractual $20 price guarantee, resulting in an accrued liability of $24 million recorded at December 31, 1998 (Note 7). The Company also executed a non-interest bearing promissory note to Shell for $6 million. Payments under this note of $3 million, $2 million and $1 million are due when the average NYMEX crude oil price for 60 consecutive calendar days equals or exceeds $18.50, $19.50 and $20.50, respectively. The total estimated purchase price of the Cook Inlet Acquisition is $44.4 million. See Note 3. On March 1, 1999, the Company and Shell entered into an amended agreement to postpone Shell's resale of Company common stock to no later than August 16, 1999. Prior to that date, the Company will have the options of purchasing the common stock from Shell, registering the shares for resale by Shell, or exchanging the shares with another Company security to be resold by Shell. In the interim, the Company has agreed to make payments to Shell of up to $20 million, including a payment of $5 million on March 2, 1999, and has entered into gas sales and transportation contracts that provide Shell with an estimated value of $7.5 million. If Shell's proceeds from the sale of Company securities exceeds the remaining amount due Shell, the difference will be refunded to the Company; otherwise, the difference will be paid to Shell. On November 20, 1998, the Company acquired primarily gas-producing properties in northwest Oklahoma and the San Juan Basin of New Mexico for $33.4 million from Seagull Energy Corp. After purchase price adjustments primarily resulting from net revenues from the October 1, 1998 effective date through November 20, 1998, the properties were purchased for an estimated price of $29.2 million. Additional purchase price revisions may result from post-closing adjustments. The Company funded the acquisition with existing lines of credit. These acquisitions have been recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for the years ended December 31, 1998 and 1997 as if these acquisitions and the April 1998 sale of common stock had been consummated as of January 1, 1998 and 1997. These pro forma results are not necessarily indicative of future results.
(in thousands, except per share data) Pro Forma (Unaudited) --------------------- 1998 1997 --------- --------- Revenues................................... $ 293,201 $ 366,041 ========= ========= Net income (loss).......................... $(64,374) $ 59,924 ========= ========= Earnings (loss) available to common stock.. $(66,153) $ 58,145 ========= ========= Earnings (loss) per common share: Basic................................ $ (1.41) $ 1.19 ========= ========= Diluted.............................. $ (1.41) $ 1.15 ========= =========
The Company filed a registration statement with the Commission in December 1998 to sell approximately 40% of the Hugoton Royalty Trust units to the public in March or April 1999 (Note 1). The unit sales price is expected to be in the range of $9.00 to $10.00. Assuming the underwriters' overallotment option is not exercised, the Company will sell 15,000,000 units, or 37.5% of the Trust. Based on a mid-range price of $9.50 per unit, net proceeds to be received by the Company is estimated to be $131.5 million, net of underwriters' discount and offering expenses. Proceeds from the sale will be used to reduce bank debt. Pro forma results of operations for the year ended December 31, 1998, as if the sale of Trust units and the acquisitions described above were consummated immediately prior to January 1, 1998, would be: revenues of $269.2 million, net loss of $63.7 million and loss available to common stock of $65.5 million, or $1.39 per common share. 54 13. Quarterly Financial Data (Unaudited) The following are summarized quarterly financial data for the years ended December 31, 1998 and 1997 (in thousands, except per share data):
Quarter -------------------------------------- 1st 2nd 3rd 4th ------- ------- -------- -------- 1998 - --------------------------------- Revenues.................... $49,968 $61,652 $ 67,044 $ 70,822 Gross profit (a)............ $13,007 $14,510 $ 16,568 $ 9,656 Earnings (loss) available to common stock.............. $ (184) $ 759 $(31,004) $(41,069) Earnings (loss) per common share Basic..................... $ 0.00 $ 0.02 $ (0.69) $ (0.90) Diluted................... $ 0.00 $ 0.02 $ (0.69) $ (0.90) Average shares outstanding.. 39,046 43,940 44,765 45,440 1997 - --------------------------------- Revenues.................... $52,286 $45,520 $ 43,734 $ 56,732 Gross profit (a)............ $24,625 $16,595 $ 14,242 $ 23,834 Earnings available to common stock.............. $10,650 $ 3,735 $ 2,779 $ 6,741 Earnings per common share Basic..................... $ 0.26 $ 0.09 $ 0.07 $ 0.17 Diluted................... $ 0.25 $ 0.09 $ 0.07 $ 0.17 Average shares outstanding.. 40,395 39,498 39,581 39,629
(a) Operating income before general and administrative expense. 14. 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):
1998 1997 1996 -------- -------- -------- Acquisitions: Producing properties.... $339,889 $251,663 $105,252 Undeveloped properties.. 514 3,964 563 Development (a)............ 69,367 86,555 44,758 Exploration (b)............ 8,034 2,088 280 -------- -------- -------- Total...................... $417,804 $344,270 $150,853 ======== ======== ========
(a) Includes capitalized interest of $1,070,000 in 1998 and $800,000 in 1997. No interest was capitalized in prior years. (b) Primarily includes geological and geophysical costs. 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 55 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. 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. 56
Oil Gas Natural Gas (Bbls) (Mcf) Liquids (Bbls) (a) --------------- --------- ------------------ Proved Reserves (in thousands) December 31, 1995........................ 39,988 358,070 Revisions.............................. 2,361 29,379 Extensions, additions and discoveries.. 2,220 37,480 Production............................. (3,508) (37,275) Purchases in place..................... 1,552 153,400 Sales in place......................... (173) (516) --------------- --------- December 31, 1996........................ 42,440 540,538 - Revisions.............................. (989) (14,182) - Extensions, additions and discoveries.. 9,263 112,906 - Production............................. (3,980) (49,587) (80) Purchases in place..................... 3,195 248,040 13,890 Sales in place......................... (2,075) (21,940) - --------------- --------- ----------------- 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 =============== ========= ================= Proved Developed Reserves December 31, 1995........................ 28,946 320,230 =============== ========= December 31, 1996........................ 31,883 466,412 =============== ========= December 31, 1997........................ 33,835 677,710 11,494 =============== ========= ================= December 31, 1998........................ 42,876 968,495 14,000 =============== ========= =================
(a) Proved reserves attributable to natural gas liquids were not considered significant prior to the Amoco Acquisition in December 1997 (Note 12). Natural gas liquids proved reserves as disclosed include only San Juan Basin properties purchased in this acquisition.
Standardized Measure of Discounted Future December 31 Net Cash Flows Relating to Proved Reserves -------------------------------------- 1998 1997 1996 ----------- ----------- ----------- (in thousands) Future cash inflows...................... $ 3,041,776 $ 2,604,453 $ 2,634,641 Future costs:............................ Production............................ (1,135,789) (979,317) (819,780) Development........................... (228,561) (140,594) (77,837) ----------- ----------- ----------- Future net cash flows before income tax.. 1,677,426 1,484,542 1,737,024 Future income tax........................ (231,249) (291,375) (450,987) ----------- ----------- ----------- Future net cash flows.................... 1,446,177 1,193,167 1,286,037 10% annual discount...................... (637,774) (551,058) (579,556) ----------- ----------- ----------- Standardized measure (a)................. $ 808,403 $ 642,109 $ 706,481 =========== =========== ===========
(a) Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $908,606,000 in 1998, $782,322,000 in 1997 and $946,150,000 in 1996. 57
Changes in Standardized Measure of Discounted Future Net Cash Flows 1998 1997 1996 ----------- ----------- ----------- (in thousands) Standardized measure, January 1........ $ 642,109 $ 706,481 $ 335,156 ----------- ----------- ----------- Revisions: Prices and costs..................... (184,568) (388,559) 360,053 Quantity estimates................... 65,600 55,497 34,099 Accretion of discount................ 71,942 86,845 37,291 Future development costs............. (104,636) (120,073) (36,267) Income tax........................... 40,011 99,455 (169,118) Production rates and other........... (296) (1,614) (155) ----------- ----------- ----------- Net revisions..................... (111,947) (268,449) 225,903 Extensions, additions and discoveries.. 96,829 92,582 49,802 Production............................. (146,498) (125,343) (97,106) Development costs...................... 56,904 73,062 33,484 Purchases in place (a)................. 271,806 207,387 160,670 Sales in place......................... (800) (43,611) (1,428) ----------- ----------- ----------- Net change........................ 166,294 (64,372) 371,325 ----------- ----------- ----------- Standardized measure, December 31...... $ 808,403 $ 642,109 $ 706,481 =========== =========== ===========
(a) 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. Year-end oil prices used in the estimation of proved reserves and calculation of the standardized measure were $9.50 for 1998, $15.50 for 1997, $24.25 for 1996 and $18.00 for 1995. Year-end average gas prices were $2.01 for 1998, $2.20 for 1997, $3.02 for 1996 and $1.68 for 1995. Year-end average natural gas liquids prices were $3.99 for 1998 and $11.07 for 1997. Proved oil and gas reserves at December 31, 1998 include 209,000 Bbls and 8,278,000 Mcf, and the standardized measure includes $7,930,000 attributable to the Company's ownership of approximately 22% of the Cross Timbers Royalty Trust. Year-end 1998 oil and gas reserves also include 3,224,000 Bbls and 412,058,000 Mcf, and the standardized measure includes $347.2 million attributable to the Company's 100% ownership of the Hugoton Royalty Trust. 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. 58 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, 1998 and 1997, and the related consolidated statements of operations, comprehensive income, cash flows and stockholders' equity for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Fort Worth, Texas March 12, 1999 59 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 9th day of April 1999. 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 9th day of April 1999. 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 Board Jack P. Randall and President J. RICHARD SEEDS SCOTT G. SHERMAN - -------------------------------------------- ---------------------------------- J. Richard Seeds, Executive Vice President Scott G. Sherman PRINCIPAL FINANCIAL OFFICER PRINCIPAL ACCOUNTING OFFICER LOUIS G. BALDWIN BENNIE G. KNIFFEN - -------------------------------------------- ---------------------------------- Louis G. Baldwin, Senior Vice President Bennie G. Kniffen, Senior Vice and Chief Financial Officer President and Controller 60 INDEX TO EXHIBITS
Exhibit No. Description Page - ------- --------------------------------------------------------------------- ---- 3.1 Certificate of Incorporation of Cross Timbers Oil Company, as amended through and restated on May 18, 1994 (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-8, File No. 33-81766) 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 Form of Certificate of Designations of Series A Convertible Preferred Stock, par value $.01 per share (incorporated by reference to Exhibit 4 to Form 8-A/A, Amendment No. 1, dated September 3, 1996) 4.2 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) 4.3 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) 4.4 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 dated September 8, 1998) 10.1 Revolving Credit Agreement dated November 16, 1998, between Cross Timbers Oil Company and certain commercial banks named therein (incorporated by reference to Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-68441) 10.2 * Employment Agreement between the Company and Bob R. Simpson, dated February 21, 1995 (incorporated by reference to Exhibit 10.6 to Form 10-K for the year ended December 31, 1994) 10.3 * Employment Agreement between the Company and Steffen E. Palko, dated February 21, 1995 (incorporated by reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 1994) 10.4 * 1991 Stock Incentive Plan (incorporated by reference to Exhibit 10.7 to Registration Statement on Form S-1, File No. 33-59820) 10.5 * Form of grant under 1991 Stock Incentive Plan (incorporated by reference to Exhibit 10.8 to Registration Statement on Form S-1, File No. 33-59820) 10.6 * 1994 Stock Incentive Plan (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-8, File No. 33-81766) 10.7 * 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)
61
Exhibit No. Description Page - ------- --------------------------------------------------------------------- ---- 10.8 * 1997 Stock Incentive Plan, as amended February 25, 1998 (incorporated by reference to Exhibit 10.8 to Form 10-K for the year ended December 31, 1997) 10.9 * 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) 10.10 * 1998 Stock Incentive Plan (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-8, File No. 333-69977) 10.11 * 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) 10.12 * 1998 Royalty Trust Option Plan (incorporated by reference to Exhibit B to the 1998 Proxy Statement filed on April 24, 1998) 10.13 * Management Group Employee Severance Protection Plan (incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 1998) 10.14 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) 10.15 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) 12.1 Computation of Ratio of Earnings to Fixed Charges (incorporated by reference to Exhibit 12.1 to Form 10-K for the year ended December 31, 1998) 21.1 Subsidiaries of Cross Timbers Oil Company (incorporated by reference to Exhibit 21.1 to Form 10-K for the year ended December 31, 1998) 23.1 Consent of Arthur Andersen LLP 23.2 Consent of Miller and Lents, Ltd. (incorporated by reference to Exhibit 23.2 to Form 10-K for the year ended December 31, 1998) * 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. 62 EX-23.1 2 CONSENT OF ARTHUR ANDERSEN LLP EXHIBIT 23.1 INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT Cross Timbers Oil Company Fort Worth, Texas As independent public accountants, we hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-64274, 33-65238, 33-81766, 333-35229 and 333-36569) and on Form S-3 (No. 333-46909) of Cross Timbers Oil Company and Form S-3 (No. 333-56983) of Cross Timbers Oil Company and Cross Timbers Royalty Trust of our report dated March 12, 1999, included in the Annual Report on Form 10-K of Cross Timbers Oil Company for the year ended December 31, 1998. ARTHUR ANDERSEN LLP Fort Worth, Texas April 9, 1999 -----END PRIVACY-ENHANCED MESSAGE-----