Item 3. LEGAL PROCEEDINGS
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 in April 1998. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which the Company has assumed the obligation to pay royalties. The plaintiffs allege that the Company has reduced royalty payments by post-production deductions and has entered into contracts with subsidiaries that were not arm's-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by the Company in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. The Company contends that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm's-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. The Company further contends that any such fees enhance the value of the gas or the products derived from the gas. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. A hearing on the class certification issue has not been scheduled. The court has ordered that the parties enter into mediation, which should occur in the first half of 2002. 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.
In October 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against the Company and certain of its subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that the Company underpaid royalties on gas produced from federal leases and lands owned by Native Americans by at least 20% during the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for the Company to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi- district litigation panel ordered that the lawsuits against the Company and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. The Company and other defendants filed a motion to dismiss the lawsuit, which was denied. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in the Company's financial statements.
In February 2000, the Department of Interior notified the Company and several other producers that certain Native American leases located in the San Juan Basin have expired due to the failure of the leases to produce in paying quantities from February through August 1990. The Department of Interior has demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. The Company has filed a Notice of Appeal with the Interior Board of Indian Appeals. 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.
In June 2001, the Company was served with a lawsuit styled Quinque Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against the Company and one of its subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. No class has been certified. The allegations in the case are similar to those in the Grynberg case; however, the Quinque case broadens the claims to cover all oil and gas leases (other than the Federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines resulting in underpayments to the plaintiffs. Plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In
September 2001, the Company filed a motion to dismiss the lawsuit, which is currently pending. In February 2002, the Company and one of its subsidiaries were dismissed from the suit and another subsidiary of the Company was added. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in the Company's financial statements.
The Company is involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on the Company's financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operating results of a given interim period or year.
Item 4.
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 2001.
PART II
Item 5.
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 2001 and 2000 (as adjusted for the three-for-two stock splits effected on September 18, 2000 and June 5, 2001):
The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Company's Board of Directors and will depend on the Company's financial condition, earnings and funds from operations, the level of its capital expenditures, dividend restrictions in its financing agreements, its future business prospects and other matters as the Board of Directors deems relevant. Furthermore, the Company's revolving credit agreement with banks restricts the amount of dividends to 25% of cash flow from operations, as defined, for the latest four consecutive quarterly periods. The Company's 9 1/4% and 8 3/4% senior subordinated notes also place certain restrictions on distributions to common stockholders, including dividend payments.
On February 19, 2002, the Board of Directors declared a quarterly dividend of $.01 per share payable on April 15, 2002 to stockholders of record on March 28, 2002. On March 1, 2002, the Company had approximately 658 stockholders of record.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The following table shows selected financial information for the five years ended December 31, 2001. Significant producing property acquisitions in each of the years presented, other than 2000, affect the comparability of year-to-year financial and operating data. See Items 1 and 2, Business and Properties, "Acquisitions." All weighted average shares and per share data have been adjusted for the three-for-two stock splits effected in March 1997, February 1998, September 2000 and June 2001. This information should be read in conjunction with Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements at Item 14(a).
(in thousands except production, per share and per unit data)
(a) Includes effect of pre-tax derivative fair value gain of $54.4 million, pre-tax non-cash incentive compensation of $9.6 million and an after-tax charge of $44.6 million for the cumulative effect of accounting change.
(b) Includes effect of pre-tax gain of $43.2 million on significant asset sales, pre-tax derivative fair value loss of $55.8 million and non-cash incentive compensation expense of $26.1 million.
(c) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton Royalty Trust units.
(d) 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.
(e) Before cumulative effect of accounting change, earnings per share were $2.39 basic and $2.35 diluted.
(f) Defined as cash provided by operating activities before changes in operating assets and liabilities and exploration expense. Because of exclusion of changes in operating assets and liabilities and exploration expense, this cash flow statistic is different from cash provided (used) by operating activities, as is disclosed under generally accepted accounting principles.
(g) For purposes of calculating this ratio, earnings include earnings (loss) available to common stock before income tax and fixed charges. Fixed charges include interest costs, the portion of rentals considered to be representative of the interest factor and preferred stock dividends.
(h) Fixed charges exceeded earnings by $108.4 million. Excluding the effect of items in (d) above, fixed charges exceeded earnings by $19 million.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with Item 6, "Selected Financial Data" and the Company's Consolidated Financial Statements at Item 14(a).
General
The following events affect the comparability of results of operations and financial condition for the years ended December 31, 2001, 2000 and 1999, and may impact future operations and financial condition. Throughout this discussion, the term "Mcfe" refers to thousands of cubic feet of gas equivalent quantities produced for the indicated period, with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
Three-for-Two Stock Splits. The Company effected three-for-two stock splits on September 18, 2000 and June 5, 2001. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect all stock splits.
2001 Acquisitions. During 2001, the Company acquired predominantly gas-producing properties at a total cost of $242 million primarily funded by bank borrowings and operating cash flow. The acquisitions include:
. Herd Acquisition. In January 2001, the Company acquired gas properties in East Texas and Louisiana for $115 million from Herd Producing Company, Inc.
. Miller Acquisition. In February 2001, the Company acquired gas properties in East Texas for $45 million from Miller Energy, Inc. and other owners.
1999 Acquisitions. During 1999, the Company acquired predominantly gas-producing properties at a total cost of $510 million primarily funded by a combination of bank borrowings, proceeds from a public offering of common stock and the issuance of common stock. The acquisitions include:
. Spring Holding Company Acquisition. In July 1999, the Company and Lehman Brothers Holdings, Inc. each acquired 50% of the common stock of Spring Holding Company for a combination of cash and the Company's common stock totaling $85 million. In September 1999, the Company acquired Lehman's 50% interest in Spring for $44.3 million. The acquisition included gas properties located in the Arkoma Basin of Arkansas and Oklahoma with a purchase price of $235 million. After purchase accounting adjustments and other costs, the cost of the properties was $257 million.
. Ocean Energy Acquisition. In September 1999, the Company and Lehman acquired Arkoma Basin gas properties for $231 million. Lehman contributed $100 million in cash and the Company contributed $100 million in securities, including its common stock, to a jointly owned company. The acquisition was funded with cash of $100 million and bank borrowings of $131 million. The Company acquired Lehman's interest in this acquisition in March 2000 for $111 million, which was funded by proceeds from the sales of producing properties and equity securities, as well as bank debt. The $11 million in excess of Lehman's investment was recorded as additional property cost in 2000.
Hugoton Royalty Trust Sales. The Company created Hugoton Royalty Trust in December 1998 by conveying 80% net profits interests in producing properties in Kansas, Oklahoma and Wyoming. In April and May 1999, the Company sold 17 million units, or 42.5%, of Hugoton Royalty Trust in its initial public offering. Total proceeds from this sale were $148.6 million, which were used to reduce bank debt. Total gain on sale, including the sale of units pursuant to an employee incentive plan, was $40.6 million before income tax. In October and November 2000, the Company sold 1.2 million units, or approximately 3%, of Hugoton Royalty Trust pursuant to the employee incentive plan at a total gain of $11 million before income tax.
2000 Property Sales. In March 2000, the Company sold oil- and gas-producing properties in Crockett County, Texas and Lea County, New Mexico for total gross proceeds of $68.3 million.
1999 Property Sales. In May and June 1999, the Company sold primarily nonoperated gas-producing properties in New Mexico for $44.9 million. In September 1999, the Company sold primarily nonoperated oil- and gas-producing
properties in Oklahoma, Texas, New Mexico and Wyoming for $63.5 million, including sales of $22.5 million of properties acquired in the Spring Holding Company Acquisition.
2001, 2000 and 1999 Development and Exploration Programs. Gas development focused on the East Texas area and the Arkoma and San Juan basins during 2001, and on the East Texas area and the Fontenelle Unit during 2000 and 1999. Oil development was concentrated in Alaska during 2001 and in the University Block 9 Field during all three years. Exploration activity has been primarily geological and geophysical analysis, including seismic studies, of undeveloped properties. Exploratory expenditures were $5.4 million in 2001, $1 million in 2000 and $900,000 in 1999. Exploration expense for 2001 includes dry hole expense of $2.2 million.
2002 Development and Exploration Program. The Company has budgeted $400 million for its 2002 development and exploration program, which is expected to be funded primarily by cash flow from operations. The Company anticipates exploration expenditures will be approximately 4% of the 2002 budget. The cost of any property acquisitions during 2002 may reduce the amount currently budgeted for development and exploration. The total capital budget, including acquisitions, will be adjusted throughout 2002 to focus on opportunities offering the highest rates of return.
Common Stock Transactions. The following significant sales and issuances of common stock occurred during the three-year period ended December 31, 2001:
. In November 2000, the Company sold 9.9 million shares of common stock from treasury with net proceeds of approximately $126.1 million. The proceeds were used to reduce bank debt.
. In July 1999, the Company sold 4.5 million shares of common stock from treasury with net proceeds of approximately $26.5 million. The proceeds were used to repurchase 4.3 million shares of common stock issued for a 1998 acquisition.
. In July 1999, the Company issued 9 million shares of common stock for its 50% interest in Spring Holding Company and for cash proceeds of $3.2 million which was used to reduce bank debt.
Treasury Stock Purchases. The Company often repurchases shares of its common stock as part of its strategic acquisition plans. The Company purchased on the open market 7.9 million shares at a cost of $41.4 million in 2000 and 11,000 shares at a cost of $53,000 in 1999. As of March 27, 2002, 6.5 million shares remain under the May 2000 Board of Directors' authorization to purchase an additional 6.8 million shares.
Conversion of Preferred Stock. In 2000 and 2001, all outstanding preferred stock was converted into 5.5 million shares of common stock.
Investment in Equity Securities. In 1998, the Company purchased what it believed to be undervalued oil and gas reserves by acquiring common stock of publicly traded independent oil and gas producers at a total cost of $167.7 million. For accounting purposes, the Company considered equity securities purchased in 1998 to be trading securities since they were purchased with the intent to resell in the near future, and therefore recognized unrealized investment gains and losses in the income statements. After selling a portion of these securities in 1998 and 1999, the Company sold its remaining investment in equity securities in 2000 for $43.7 million. The Company recognized a gain of $13.3 million in 2000 and a loss of $1.1 million in 1999 related to this investment.
Hedging Activities. The Company enters futures contracts, collars and swap agreements, as well as fixed price physical delivery contracts, to hedge against unfavorable changes in product prices. During 2001, all hedging activities increased gas revenue by $97 million. Hedging activities reduced gas revenue by $40.5 million in 2000 and by $5.7 million in 1999, and reduced oil revenue by $7.8 million in 2000 and by $2.2 million in 1999.
Cumulative Effect of Accounting Change for Derivatives. On January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133 by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in accounting principle and an unrealized loss of $67.3 million in accumulated other comprehensive income, which is an element of stockholders' equity. The unrealized loss was related to the derivative fair value of cash flow hedges. The charge to the income statement was primarily related to the Company's gas physical delivery contract at crude oil-based prices.
Derivative Fair Value Gain/Loss. The Company has recorded realized derivative gains and losses in its income statements and unrealized derivative gains and losses associated with cash flow hedges in accumulated other comprehensive income. The Company recorded a $54.4 million gain in 2001 and a $55.8 million loss in 2000 related to changes in fair value of non-hedge derivatives. The 2000 loss and $29.5 million of the 2001 gain are related to the change in fair value of call options that the Company sold in 1999 as part of its hedging activities. Because written call options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. Most of the remaining gain in 2001 is related to the change in fair value of a gas physical delivery contract with crude oil-based pricing, the loss on which was initially recorded in the cumulative effect of accounting change for derivatives.
At December 31, 2001, the Company has recorded a net unrealized gain of $70.6 million (net of $38.1 million tax) in accumulated other comprehensive income related to the fair value of derivatives designated as cash flow hedges. The ultimate settlement value of these hedges will be recognized in the income statement as gas revenue when the related production occurs through 2002. The Company also has fixed price gas physical delivery contracts that are not expected to be net cash settled, and therefore, their fair value of $36.4 million is not recorded in the financial statements. Revenues from these contracts will be recognized as the commodity is delivered.
Enron Corporation Bankruptcy. As of December 2, 2001, the date of its bankruptcy filing, Enron Corporation was the counterparty to some of the Company's hedge derivative contracts, as well as purchaser of natural gas under certain physical delivery contracts. One of these contracts was a natural gas physical delivery contract with crude oil-based pricing, also referred to as the Enron Btu swap contract. The Company terminated its contracts with Enron and has recorded a net receivable of $21.3 million related to gas physical deliveries and hedge derivative fair value at the contract termination dates. An additional $14.1 million is due from Enron for net unrealized gains related to undelivered gas under physical delivery contracts, which has not been recorded in the Company's financial statements. In accordance with termination provisions of the Enron Btu swap contract, the Company believes that it no longer has a liability to Enron under this contract. However, until this debt is legally extinguished, the $43.3 million fair value liability of this contract at the date of termination must remain recorded in the Company's financial statements. In the event the termination provisions of the Enron Btu swap contract are ultimately not enforced, the Company believes that it should have the right to offset all amounts due from Enron, including amounts related to undelivered gas under physical delivery contracts, against any Enron Btu swap contract liability. Because this liability exceeds net receivables from Enron, no reserve for asset collectibility is anticipated to be necessary. The final resolution of the Enron bankruptcy and related proceedings may result in a settlement materially different from amounts recorded at December 31, 2001. See Note 7 to Consolidated Financial Statements.
Incentive Compensation. Incentive compensation results from stock appreciation right, performance share and royalty trust option awards, and subsequent changes in the Company's stock price. Incentive compensation totaled $9.6 million in 2001 and $26.1 million in 2000, which was primarily related to performance share grants, as well as royalty trust option exercises in 2000. Incentive compensation was not significant in 1999. As of December 31, 2001, there were 159,000 performance shares outstanding that vest when the common stock price reaches $18.30, 242,000 performance shares outstanding that vest when the common stock price reaches $21.67 and 13,500 performance shares that vest in increments of 6,750 in each of 2002 and 2003. In February 2002, upon vesting of the performance shares with the $18.30 common stock vesting price, an additional 159,000 performance shares were issued that vested when the stock price reached $20.00 in March 2002.
Product Prices. In addition to supply and demand, oil and gas prices are affected by seasonal, political and other conditions the Company generally cannot control or predict.
Oil. Crude oil prices are generally determined by global supply and demand. After OPEC members and other oil producers agreed to production cuts in March 1999, oil prices climbed through the remainder of 1999 and first quarter 2000. Despite OPEC production increases in 2000, increased demand sustained higher prices. The West Texas Intermediate ("WTI") posted price reached $34.25 per Bbl in September 2000, its highest level in ten years. Lagging demand in 2001, attributable to a worldwide economic slowdown, caused oil prices to decline. OPEC members agreed to cut daily production by one million barrels in April 2001 and an additional one million barrels in September 2001 to adjust for weak demand and excess supply. The economic decline was accelerated by the terrorist attacks in the United States on September 11, 2001, placing further downward pressure on oil prices. In December, OPEC announced additional production cuts of 1.5 million barrels per day effective January 1, 2002, for six months. The Company uses commodity price hedging instruments to reduce its exposure to oil price fluctuations. Excluding the effect of these
hedging instruments, the Company's average oil price was $28.72 in 2000 and $17.37 in 1999. The Company did not hedge oil prices in 2001 and its average oil price was $23.49. With economic recoveries in the U.S. and global markets, oil prices have strengthened during 2002. At March 26, 2002, the average NYMEX oil price for the following 12 months was $24.91 per Bbl. The Company estimates that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $4.6 million change in 2002 annual operating cash flow.
Gas. Natural gas prices are dependent upon North American supply and demand, which is affected by weather conditions. Natural gas competes with alternative energy sources as a fuel for heating and the generation of electricity. The 1999 average price was lower because of high levels of gas remaining in storage from the abnormally warm winter of 1998-1999. Gas prices began to increase in May 1999 and, after declining briefly at year end, strengthened in 2000, reaching a record high of $10.10 per MMBtu in December 2000 as winter demand strained gas supplies. Gas prices declined during 2001 because of fuel switching due to higher prices, milder weather and a weaker economy, which has reduced the demand for gas to generate electricity and resulted in sharply increased gas storage levels. Despite the winter of 2001-2002 being one of the warmest on record and the likely result that storage levels will be higher than historical averages at the end of the heating season, gas prices have increased during 2002 and are expected to remain volatile. At March 26, 2002, the average NYMEX gas price for the following 12 months was $3.63 per MMBtu. The Company uses commodity price hedging instruments, including fixed price delivery contracts, to reduce its exposure to gas price fluctuations. Excluding the effect of these hedging instruments, the Company's average gas price was $3.87 in 2001, $3.70 in 2000 and $2.18 in 1999. The Company has hedges in place on approximately 95% of April through December 2002 projected production, including futures and fixed price contracts with an average weighted NYMEX price of $3.71 for 67% of production, and collars that provide an average weighted NYMEX floor price of $3.03 and ceiling price of $3.62 for 28% of production. Including the effects of gains on closed futures contracts, these collars provide a floor price of $3.31 and a ceiling price of $3.90. After the effects of hedging, the Company estimates that a $0.10 per Mcf increase or decrease in the average gas sales price would result in a $5.6 million change in 2002 annual operating cash flow, subject to floor and ceiling prices provided by the collars.
The following summarizes the Company's April through December 2002 gas hedging positions at March 27, 2002, as are further detailed in Note 8 to the Consolidated Financial Statements. Prices to be realized for hedged production may be less than these NYMEX prices because of location, quality and other adjustments.
(a) Includes $0.05 per Mcf gain that will be deferred and recognized in 2003 related to contract terminations and hedge redesignations. Physical contract prices have been converted from index to NYMEX price using estimated delivery point basis.
(b) Includes $0.10 per Mcf reduction for cost of collars.
(c) Gain on closed futures contracts per Mcf of collars. Includes average gains of $0.20 per Mcf on terminated Enron contracts.
(d) Includes gain on closed futures contracts per (c) above.
Impairment Provision. The Company regularly determines whether an impairment provision is needed for producing properties 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. The Company has not recorded impairment of producing properties since a $2 million provision was recorded in 1998. If oil and gas prices significantly decline, the Company may be required to record impairment provisions for producing properties in the future, which could be material.
Results of Operations
2001 Compared to 2000
For the year 2001, earnings available to common stock were $248.8 million compared with earnings of $115.2 million for 2000. Earnings for 2001 include a $44.6 million after-tax charge for adoption of the new derivative accounting principle, SFAS No. 133, an after-tax derivative fair value gain of $35.3 million and a $6.4 million after-tax charge for incentive compensation and loss on sale of properties. The 2000 earnings include a $7.3 million after-tax gain from the sale of Hugoton Royalty Trust units, a $13.1 million after-tax gain on sale of properties, an $8.8 million after-tax gain on investment in equity securities, a $17.3 million after-tax charge for incentive compensation and a $36.8 after-tax derivative fair value loss. Excluding these gains and losses from asset sales, changes in derivative fair value and incentive compensation, earnings for 2001 were $264.5 million, compared with $140.1 million for 2000.
Revenues for 2001 were $838.7 million, or 40% above 2000 revenues of $600.9 million. Oil revenue decreased $11.3 million, or 9%, because of a 13% decrease in oil prices from an average of $27.07 per Bbl in 2000 to $23.49 in 2001 (see "General - Product Prices - Oil" above), partially offset by a 5% increase in oil production. Increased production was primarily because of the 2001 development program.
Gas and natural gas liquids revenue increased $253.5 million, or 56%, because of a 21% increase in gas production and a 33% increase in gas prices from an average of $3.38 per Mcf in 2000 to $4.51 in 2001 (see "General - Product Prices - Gas" above). These increases were partially offset by a 1% decrease in natural gas liquids production and a 21% decrease in natural gas liquids prices from an average price of $19.61 per Bbl in 2000 to $15.41 in 2001. Increased gas production was attributable to the 2001 development program. Decreased gas liquids production was primarily because higher gas prices in first quarter 2001 made ethane extraction uneconomical at some gas plants.
Gas gathering, processing and marketing revenues decreased $3.3 million primarily because of decreased processing margins. Other revenues declined $1.1 million primarily because of decreased gains on sale of properties.
Expenses for 2001 totaled $327.8 million as compared with total 2000 expenses of $388.7 million. Excluding derivative fair value (gain) loss, expenses for 2001 totaled $382.2 million, or 15% above total expenses of $332.9 for 2000. Most expenses increased in 2001 because of acquisitions and development and related increased production.
Production expense increased $23 million, or 26%, because of increased production, as well as higher maintenance, overhead, fuel, pumper and workover expense. Production expense per Mcfe increased $0.04. The Company's 2001 exploration expense was $5.4 million compared with $1 million for 2000 because of dry hole costs of $2.2 million and increased geological and geophysical costs.
Taxes, transportation and other deductions increased 12%, or $7 million, primarily because of increased oil and gas revenues. Taxes, transportation and other per Mcfe decreased 6% from $0.35 to $0.33 primarily because of lower severance tax rates on new wells in East Texas.
Depreciation, depletion and amortization ("DD&A") increased $24.5 million, or 19%, primarily because of increased production and higher acquisition and drilling costs. On an Mcfe basis, DD&A increased slightly from $0.79 in 2000 to $0.81 in 2001.
General and administrative expense decreased $10.2 million, or 21%, because of decreased incentive compensation of $16.5 million which was offset by increased expenses from Company growth. Excluding incentive compensation, general and administrative expense per Mcfe increased from $0.14 in 2000 to $0.15 in 2001.
The derivative fair value gain of $54.4 million in 2001 primarily reflects the effect of decreased natural gas prices during the year on the fair value of outstanding call options and a gas physical delivery contract with crude oil-based pricing. The derivative fair value loss of $55.8 million in 2000 reflects the effect of increased prices during the period on the fair value of call options. These derivatives do not qualify for hedge accounting. See Note 6 to Consolidated Financial Statements.
Interest expense decreased $23.3 million, or 30%, primarily because of a 19% decrease in the weighted average interest rate, an 11% decrease in weighted average borrowings and increased capitalized interest. Interest expense per Mcfe decreased 40% from $0.48 in 2000 to $0.29 in 2001.
2000 Compared to 1999
For the year 2000, earnings available to common stock were $115.2 million compared with earnings of $45 million for 1999. The 2000 earnings include a $7.3 million after-tax gain from the sale of Hugoton Royalty Trust units, a $13.1 million after-tax gain on sale of properties, an $8.8 million after-tax gain on investment in equity securities, a $17.3 million after-tax charge for incentive compensation and a $36.8 million after-tax loss on the change in derivative fair value. The 1999 earnings include a $26.8 million after-tax gain from the sale of Hugoton Royalty Trust units, a $4.2 million after-tax gain on sale of properties and an $800,000 after-tax loss on investment in equity securities. Excluding these gains and losses from asset sales, changes in derivative fair value and incentive compensation, earnings for 2000 were $140.1 million, compared with $14.8 million for 1999.
Revenues for 2000 were $600.9 million, or 76% above 1999 revenues of $341.3 million. Oil revenue increased $41.6 million, or 48%, because of a 60% increase in oil prices from an average of $16.94 per Bbl in 1999 to $27.07 in 2000 (see "General - Product Prices - Oil" above), partially offset by a 7% decrease in oil production. Decreased production was primarily because of the 2000 property sales.
Gas and natural gas liquids revenue increased $217.8 million, or 91%, because of a 20% increase in gas production, a 22% increase in natural gas liquids production, a 59% increase in gas prices from an average of $2.13 per Mcf in 1999 to $3.38 in 2000 and a 66% increase in natural gas liquids prices from an average price of $11.80 per Bbl in 1999 to $19.61 in 2000 (see "General - - Product Prices - Gas" above). Increased gas and natural gas liquids production was attributable to the 1999 acquisitions and the 1999 and 2000 development programs.
Gas gathering, processing and marketing revenues increased $5.5 million primarily because of higher gas and natural gas liquids prices, increased margin and increased volumes from the 1999 acquisitions. Other revenues were $5.3 million lower primarily because of decreased gains on sale of properties.
Expenses for 2000 totaled $388.7 million as compared with total 1999 expenses of $245.9 million. Most expenses increased in 2000 because of the 1999 acquisitions and the 1999 and 2000 development programs.
Production expense increased $10.9 million, or 14%, because of increased production related to the 1999 acquisitions and 1999 and 2000 development programs. Production expense per Mcfe remained flat at $0.53. The Company's 2000 exploration expense of $1 million, which was predominantly geological and geophysical costs, remained about the same as 1999.
Taxes, transportation and other deductions increased 68% or $23 million because of increased oil and gas revenues, as well as increased transportation, compression and other charges related to the 1999 acquisitions and the 1999 and 2000 development programs. Taxes, transportation and other per Mcfe increased 52% from $0.23 to $0.35 because of increased prices and other deductions.
DD&A increased $17.4 million, or 16%, primarily because of the 1999 acquisitions and the 1999 and 2000 development programs. On an Mcfe basis, DD&A increased slightly from $0.78 in 1999 to $0.79.
General and administrative expense increased $35.4 million, or 251% because of incentive compensation of $26.1 million and increased expenses from Company growth related to the 1999 acquisitions. Excluding incentive compensation, general and administrative expense per Mcfe increased from $0.10 in 1999 to $0.14 in 2000.
Interest expense increased $14.7 million, or 23%, primarily because of a 7% increase in weighted average borrowings and an 8% increase in the weighted average interest rate. Interest classified as part of the gain (loss) on investment in equity securities decreased $4.6 million from 1999. Interest expense per Mcfe increased from $0.45 in 1999 to $0.48 in 2000.
Liquidity and Capital Resources
The Company's primary sources of liquidity are cash flow from operating activities, borrowings against the revolving credit facility, occasional producing property sales (including sales of royalty trust units) and public offerings of equity and debt. Other than for operations, the Company's cash requirements are generally for the acquisition, exploration and development of oil and gas properties, and debt and dividend payments. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. The Company believes that its sources of liquidity are adequate to fund its cash requirements in 2002.
Cash provided by operating activities was $542.6 million in 2001, compared with cash provided by operating activities of $377.4 million in 2000 and $133.3 million in 1999. Increased operating cash flow during this three-year period was primarily because of increased prices and production from acquisitions and development activity. Before changes in operating assets and liabilities and exploration expense, cash flow from operations was $549.6 million in 2001, $344.6 million in 2000 and $132.7 million in 1999. Operating cash flow is largely dependent upon the prices received for oil and gas production. The Company has hedged approximately 95% of its projected April through December 2002 gas production, including futures and fixed price contracts that hedge 67% of production and collars that hedge 28% of production. See "Product Prices" under "General" above.
The Company does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect its liquidity or the availability of capital resources.
Financial Condition
Total assets increased 34% from $1.6 billion at December 31, 2000 to $2.1 billion at December 31, 2001, primarily because of Company growth related to acquisitions and development. As of December 31, 2001, total capitalization was $1.7 billion, of which 51% was long-term debt. Capitalization at December 31, 2000 was $1.3 billion of which 61% was long-term debt. The decrease in the debt-to-capitalization ratio from year-end 2000 to 2001 is primarily because of increased earnings and accumulated other comprehensive income which is related to the unrealized fair value gain on hedge derivatives.
Working Capital
The Company generally maintains low cash and cash equivalent balances because it uses available funds to reduce bank debt. Short-term liquidity needs are satisfied by bank commitments under the loan agreement (see "Financing" below). Because of this, and since the Company's principal source of operating cash flows (i.e., proved reserves to be produced in the following year) cannot be reported as working capital, the Company often has low or negative working capital. The increase from negative working capital of $25.3 million at December 31, 2000 to working capital of $37.5 million at December 31, 2001 was primarily attributable to the derivative fair value asset, net of deferred income taxes, recorded during 2001 related to adoption of SFAS No. 133, the new derivative accounting principle.
Financing
On December 31, 2001, borrowings under the revolving credit agreement with commercial banks were $556 million with unused borrowing capacity of $244 million. The interest rate of 3.45% at December 31, 2001 is based on the one-month London Interbank Offered Rate plus 1.375%. Based on the value of the Company's reserves, the borrowing base increased to $1.2 billion effective June 30, 2001. The bank's total commitment, however, remains at $800 million, resulting in no increase to the Company's 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. Based on reserve values at December 31, 2001 and using parameters specified by the banks, the borrowing base remains in excess of the $800 million commitment. Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at
any time without penalty. The Company may renegotiate the loan agreement to increase borrowing capacity and extend the revolving facility. In February 2001, the loan agreement was amended to allow the repurchase of the Company's subordinated debt and to increase commodity hedging limits. In May 2001, the loan agreement was amended to allow the Company to issue senior debt.
The 1999 acquisitions were partially funded by the sale and issuance of common stock, cash flow from operations and contributions from Lehman, the Company's equity partner until it later purchased Lehman's interest in these acquisitions. These transactions are described under "General" above. See also "Capital Expenditures" below.
In October 2001, the Company filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities, preferred stock, common stock or warrants to purchase debt securities, preferred stock or common stock. The total price of securities to be offered is $600 million, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities are to be used for general corporate purposes, including reduction of bank debt. As of March 2002, no securities have been issued under the shelf registration.
Capital Expenditures
In 2001, exploration and development cash expenditures totaled $386.5 million compared with $155.4 million in 2000. The Company has budgeted $400 million for the 2002 development and exploration program. As it has done historically, the Company expects to fund the 2002 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.
Because of their size, the 1999 acquisitions were made jointly with Lehman as a 50% equity partner. The Company acquired Lehman's interest in the Spring Holding Acquisition in September 1999. The Company purchased Lehman's interest in the Ocean Energy Acquisition in March 2000 for $111 million, funded primarily by the proceeds from sales of property and equity security investments.
The Company plans to fund any future property acquisitions through a combination of cash flow from operations and proceeds from asset sales, bank debt, public equity or debt transactions. There are no restrictions under the Company's revolving credit agreement that would affect the Company's ability to use its remaining borrowing capacity for acquisitions of producing properties.
In 2000, the Board of Directors authorized the repurchase of a total of 12.4 million shares of the Company's common stock. During 2000, the Company repurchased 7.9 million shares of its common stock at a cost of $41.4 million, including 2 million shares repurchased under a 1998 Board authorization. No shares were repurchased in 2001. As of March 27, 2002, 6.5 million shares are available for repurchase.
To date, the Company has not spent significant amounts to comply with environmental or safety regulations, and it does not expect to do so during 2002. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.0045 per common share from 1999 through second quarter 2000, $0.0067 per common share for third quarter 2000 through first quarter 2001 and $0.01 per common share for the remainder of 2001. The Company's ability to pay dividends is dependent upon available cash flow, as well as other factors. In addition, the Company's bank loan agreement restricts the amount of common stock dividends and treasury stock repurchases to 25% of cash flow from operations, as defined, for the last four quarters.
Contractual Obligations and Commitments
The following summarizes the Company's significant obligations and commitments to make future contractual payments as of December 31, 2001. The Company has not guaranteed the debt of any other party, nor does the Company have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.
Long-Term Debt. Borrowings under the Company's senior bank revolving credit facility were $556 million at December 31, 2001. Bank debt is not due until May 2005, but may be prepaid at any date. The Company may renegotiate its bank debt to increase borrowing capacity and extend its maturity. Subordinated debt totaled $300 million at December 31, 2001. Of that amount, $125 million is due in April 2007 and $175 million is due in November 2009. Subordinated debt may be redeemed at a price of approximately 105% in 2002. For further information regarding long-term debt, see Note 3 to Consolidated Financial Statements.
Operating Leases. The Company's minimum lease payment commitments under noncancelable lease agreements totaled $90 million at December 31, 2001. Estimated annual payments under these lease agreements for the next five years are disclosed in Note 5 to Consolidated Financial Statements. Estimated annual payments total $15.5 million for 2002 and decline for subsequent years.
Drilling Contracts. The Company has minimum drilling rig use payments of $9.5 million in 2002 and $1 million in 2003. These costs are part of the Company's budgeted capital expenditures of $400 million for 2002.
Derivative Hedge Contracts. The Company has entered into futures contracts and swaps to hedge its exposure to natural gas price fluctuations. Because the contractual fixed price generally exceeds the current market gas price, the Company expects to receive payments from counterparties under most of these contracts. If market gas prices increase, the Company could be required to make payments under these contracts, which would be funded by the higher price received from the sale of Company gas production. See Note 6 to Consolidated Financial Statements.
For further information regarding commitments, see Note 5 to Consolidated Financial Statements.
Related Party Transactions
The Company has limited related party transactions, as further disclosed in Note 2 to Consolidated Financial Statements. During 1998 and 1999, the Company loaned five of its officers $7.3 million pursuant to full recourse promissory notes to pay margin debt in broker accounts in which the officers held Company common stock. In May 2001, officers sold 302,000 shares of common stock to the Company for $6.5 million and used the proceeds to partially repay their loans. These loans were fully repaid in 2001. The interest rate charged on these loans was equal to the Company's bank debt rate.
A company, partially owned by one of the Company's directors, performs acquisition and divestiture consulting for the Company. This director-related company received consulting fees of $994,000 in 2000. It also represented the purchaser of properties sold by the Company during 1999, and also invested in the purchase. This director-related company also performed consulting services in connection with a 1998 producing property acquisition and was entitled to receive, at its election, either a 20% working interest or a 1% overriding royalty interest conveyed from the Company's 100% working interest in the properties after payout of acquisition and operating costs. The Company acquired this potential interest from the director-related company and other parties in 2001 for a price of $15 million, pursuant to an independent fairness opinion. The director-related company received $10 million of the purchase price.
Critical Accounting Policies
The Company's financial position and results of operations are significantly affected by accounting policies and estimates related to its oil and gas properties, proved reserves, and commodity prices and risk management, as summarized below.
Oil and Gas Property Accounting
Oil and gas exploration and production companies may elect to account for their property costs using either the "successful efforts" or "full cost" accounting method. Under the successful efforts method, unsuccessful exploratory well costs, as well as all exploratory geological and geophysical costs, are expensed. Under the full cost method, all exploration costs are capitalized, regardless of success. Selection of the oil and gas accounting method can have a significant impact on a company's financial results. The Company, which generally pursues acquisition and development of proved reserves as opposed to exploration activities, follows the successful efforts method of accounting.
Property costs must be expensed through an impairment provision if in excess of the estimated future cash flows of proved reserves. The Company evaluates possible impairment of producing properties when conditions indicate that they may be impaired. Cash flow pricing estimates are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Individually significant undeveloped properties are reviewed for impairment on a property-by-property basis, and impairment of other undeveloped properties is done on a total basis. The Company's impairment of producing properties has been limited to a $2 million provision recorded in 1998. By comparison, full cost companies must generally record higher impairment provisions under a "ceiling test" which is computed using discounted estimated future after-tax cash flows based on current market prices.
Oil and Gas Reserves
The Company's proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. 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 changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.
Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. If estimated proved reserves decline, future DD&A expense will increase and net income will be reduced. A decline in proved reserves also can result in a required impairment provision, as discussed under "Oil and Gas Property Accounting" above.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 15 to Consolidated Financial Statements, are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management's estimated current market value of proved reserves.
Commodity Prices and Risk Management
Commodity prices significantly affect the Company's operating results, financial condition, cash flows and ability to borrow funds. Current market oil and gas prices are affected by supply and demand as well as seasonal, political and other conditions which the Company generally cannot control. Oil and gas prices and markets are expected to continue their historical volatility. See "General- Product Prices" above.
The Company attempts to reduce its price risk by entering into financial instruments such as gas futures contracts, collars and swap agreements, as well as fixed priced physical delivery contracts. While these instruments guarantee a certain price and, therefore, a certain cash flow, there is the risk that the Company will not be able to realize the benefit of rising prices. These contracts also expose the Company to credit risk of non-performance by the contract counterparties, which the Company attempts to limit by obtaining letters of credit or other appropriate security. The Company also has sold call options as part of its hedging program. Call options, however, do not provide a hedge
against declining prices and there is the risk that the call sales proceeds will be less than the benefit a higher sales price would have provided.
During 2001, the Company's commodity price hedging activities resulted in a $0.64 per Mcf increase in the average gas price. During 2000, the Company's commodity price hedging activities resulted in a $0.32 per Mcf reduction in the average gas price and a $1.65 per Bbl reduction in the average oil price. Based on cash flow hedges and physical delivery contracts in place at March 27, 2002, the Company estimates that it has hedged approximately 95% of its April through December 2002 projected production, including futures and fixed price contracts that hedge 67% of production, and collars that hedge 28% of production.
While the Company's price risk management activities decrease the volatility of cash flows, they may obscure the Company's operating results and financial condition. As required under generally accepted accounting principles, the Company adopted SFAS No. 133 on January 1, 2001 with a significant charge to its income statement and equity related to recording derivative financial instruments at their market value. Subsequent to that date, the Company recorded significant derivative fair value gains in the income statement and equity related to decline in natural gas prices. During 2000, the Company recorded a significant loss related to the fair value of call options. In each instance, these are projected gains and losses that will be realized upon settlement of these contracts in future periods when related production occurs. These gains and losses are offset by increases and decreases in the market value of the Company's proved reserves, which are not reflected in the financial statements. Also, a significant portion of the Company's gas price hedging is provided by fixed price physical delivery contracts which had a fair value of $36.4 million at December 31, 2001. This asset is not recorded in the Company's financial statements since the contracts are deemed to be normal sales that are not expected to be net cash settled, and therefore are not derivatives. Derivatives that provide effective cash flow hedges are designated as hedges and the Company defers related fair value gains and losses in accumulated other comprehensive income until the hedged transaction occurs. Because hedge accounting is not required under generally accepted accounting principles, the Company's operating results as reflected in its financial statements may not be comparable to other companies.
See Item 7A, "Commodity Price Risk" for the effect of price changes on derivative fair value gains and losses.
Accounting Pronouncements
During 2001, the Financial Accounting Standards Board issued the following Statements of Financial Accounting Standards:
. SFAS No. 141, Business Combinations, requires the use of the purchase method of accounting, as opposed to the pooling-of-interests method, for all business combinations initiated or completed after June 30, 2001. It supersedes APB Opinion No. 16, Business Combinations, and SFAS No. 38, Accounting for Preacquisition Contingencies of Purchased Enterprises. The adoption of SFAS No. 141 should have no material affect on the Company's financial statements since it has historically used the purchase method of accounting to record business combinations.
. SFAS No. 142, Goodwill and Other Intangible Assets, changes the method of accounting for acquired goodwill and other tangible assets, and supersedes APB Opinion No. 17, Intangible Assets. Goodwill and intangible assets with indefinite lives will no longer be amortized and will be tested at least annually for impairment. The provisions of SFAS No. 142 are required to be applied to fiscal years beginning after December 15, 2001 and should not have a material effect on the Company's financial statements.
. SFAS No. 143, Accounting for Asset Retirement Obligations, amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the cost of the long-lived asset. The statement is required to be adopted for fiscal years beginning after June 15, 2002. The effect of the Company's adoption of SFAS No. 143 has not been determined but is currently not expected to be material.
. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of. With this pronouncement, the FASB establishes a single accounting model for long-lived assets to be disposed of by sale, including the reporting of discontinued operations. The statement is required to be adopted for fiscal years beginning after December 15, 2001. The effect of the Company's adoption of SFAS No. 144 has not been determined but is currently not expected to be material.
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. Accordingly, revenue is deferred for gas deliveries in excess of the Company's net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. The consolidated balance sheets include the following amounts related to production imbalances:
Forward-Looking Statements
Certain information included in this annual report and other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by the Company, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company's operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures, cash flow, drilling activity, acquisition and development activities, pricing differentials, operating costs, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, regulatory matters and competition. Such forward-looking statements are based on management's current plans, expectations, assumptions, projections and estimates and are identified by words such as "expects," "intends," "plans," "projects," "predicts," "anticipates," "believes," "estimates," "goal," "should," "could," "assume," and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.
Among the factors that could cause actual results to differ materially are:
. crude oil and natural gas price fluctuations,
. changes in interest rates,
. the Company's ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling,
. higher than expected production costs and other expenses,
. potential delays or failure to achieve expected production from existing and future exploration and development projects,
. volatility of crude oil and natural gas prices and related financial derivatives,
. basis risk and counterparty credit risk in executing commodity price risk management activities,
. potential liability resulting from pending or future litigation, and
. competition in the oil and gas industry as well as competition from other sources of energy.
In addition, these forward-looking statements may be affected by general domestic and international economic and political conditions.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company only enters derivative financial instruments in conjunction with its hedging activities. These instruments principally include interest rate swap agreements and commodity futures, collars, swaps and option agreements. These financial and commodity-based derivative contracts are used to limit the risks of fluctuations in interest rates and natural gas and crude oil prices. Gains and losses on these derivatives are generally offset by losses and gains on the respective hedged exposures.
The Board of Directors has adopted a policy governing the use of derivative instruments, which requires that all derivatives used by the Company relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. The policy also requires review and approval by the Chairman or the Executive Vice President - Administration of all risk management programs using derivatives and all derivative transactions. These programs are also reviewed at least annually by the Board of Directors.
Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and product prices. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
Interest Rate Risk
The Company is exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At December 31, 2001, the Company's variable rate debt had a carrying value of $556 million, which approximated its fair value, and the Company's fixed rate debt had a carrying value of $300 million and an approximate fair value of $314.7 million. The Company attempts to balance the benefit of lower cost variable rate debt that has inherent increased risk with more expensive fixed rate debt that has less market risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate subordinated debt, as well as the use of interest rate swaps.
The following table shows the carrying amount and fair value of long-term debt and interest rate swaps, and the hypothetical change in fair value that would result from a 100-basis point change in interest rates. Unless otherwise noted, the hypothetical change in fair value could be a gain or a loss depending on whether interest rates increase or decrease.
(a) This is approximate gain in fair value of long-term debt and loss in fair value of interest rate swaps from a 100-basis point increase in interest rates. Because of the limitation in value caused by the 2002 call price of the Company's fixed rate debt, a 100-basis point decrease in interest rates would not significantly affect fair value at December 31, 2001.
Commodity Price Risk
The Company hedges a portion of its price risks associated with its crude oil and natural gas sales. As of December 31, 2001, the Company had outstanding gas futures contracts, swap agreements and gas basis swap agreements. These contracts and agreements had a net fair value gain of approximately $97.6 million at December 31, 2001 and a net fair value loss of $108.9 million at December 31, 2000. Of the December 31, 2001 fair value, a $98.4 million gain has been determined based on the exchange-trade value of NYMEX contracts and an $800,000 loss has been determined based on the broker bid and ask quotes for basis contracts. These fair values approximate amounts confirmed by the counterparties.
The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $27.8 million in the fair value of gas futures contracts and swap agreements at December 31, 2001. This sensitivity does not include physical product delivery contracts, which are not expected to be settled in cash or another financial instrument; these contracts had a fair value gain of $36.4 million at December 31, 2001. See Note 8 to Consolidated Financial Statements.
Because these futures contracts and swap agreements are designated hedge derivatives, changes in their fair value are reported as a component of accumulated other comprehensive income until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to product revenues in the consolidated income statement.
In conjunction with its hedging activities, the Company sold call options to sell future gas production at certain ceiling prices. Call options outstanding had a fair value loss of $44.2 million at December 31, 2000. All call options were settled in 2001 with payments to the counterparties totaling $14.7 million, resulting in a 2001 derivative fair value gain of $29.5 million.
The Company had a physical delivery contract to sell 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract was priced based on crude oil, which is not clearly and closely associated with natural gas prices, it was accounted for as a non-hedge derivative financial instrument under SFAS No. 133 beginning January 1, 2001. This contract (referred to as the Enron Btu swap contract) was terminated in December 2001 in conjunction with the bankruptcy filing of Enron Corporation, and as a result, the Company believes that its liability under this contract was reduced to zero. A $43.3 million current liability will remain on the Company's consolidated balance sheet until this contractual liability is legally extinguished. See Note 7 to Consolidated Financial Statements and "General - Enron Corporation Bankruptcy" above.
In November 2001, the Company entered derivative contracts to effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. The net fair value loss on these contracts at December 31, 2001 was $4.1 million. Of this fair value, a $6.1 million gain has been determined based on the exchange-trade value of NYMEX contracts and a $10.2 million loss has
been based on Company estimated oil prices for periods beyond 2004 for which there are not readily available exchange-trade values. These values approximate amounts confirmed by the counterparty. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $350,000 in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of approximately $150,000. In March 2002, the Company terminated contracts with maturities of May through December 2002 and received $6.6 million from the counterparty. Because these contracts are non-hedge derivatives, most of the related $6.6 million gain related to their termination was recorded in 2001 derivative fair value gain.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following financial statements and supplementary information are included under Item 14(a):
Page ----
Consolidated Balance Sheets ............................................... 37 Consolidated Income Statements ............................................ 38 Consolidated Statements of Cash Flows ..................................... 39 Consolidated Statements of Stockholders' Equity ........................... 40 Notes to Consolidated Financial Statements ................................ 41 Selected Quarterly Financial Data (Note 14 to Consolidated Financial Statements) .......................... 65 Information about Oil and Gas Producing Activities (Note 15 to Consolidated Financial Statements) .......................... 66 Report of Independent Public Accountants .................................. 69
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Item 11.
Item 11. EXECUTIVE COMPENSATION
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Item 13.
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 Securities and Exchange Commission no later than April 30, 2002.
PART IV
Item 14.
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, 2001 and 2000... 37
Consolidated Income Statements for the years ended December 31, 2001, 2000 and 1999.......................... 38
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999.......................... 39
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2001, 2000 and 1999.............. 40
Notes to Consolidated Financial Statements.................. 41
Report of Independent Public Accountants.................... 69
2. Financial Statement Schedules:
Schedule II - Consolidated Valuation and Qualifying Accounts
All other financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated financial statements.
(b) Reports on Form 8-K
The Company filed the following reports on Form 8-K during the quarter ended December 31, 2001 and through March 30, 2002:
On December 6, 2001, the Company filed a report on Form 8-K to disclose that its gas production growth projections and financial performance should not be materially affected by transactions with Enron Corporation and its affiliates.
On December 19, 2001, the Company filed a report on Form 8-K to announce that its Board of Directors approved a $400 million exploration and development budget for 2002 that targets a 20% growth in total gas production over 2001 levels.
(c) Exhibits
See Index to Exhibits at page 72 for a description of the exhibits filed as a part of this report. Documents filed prior to June 1, 2001, were filed with the Securities and Exchange Commission under the Company's prior name, Cross Timbers Oil Company.
XTO ENERGY INC. Consolidated Balance Sheets - --------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
XTO ENERGY INC. Consolidated Income Statements - -------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
XTO ENERGY INC. Consolidated Statements of Cash Flows - --------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
XTO ENERGY INC. Consolidated Statements of Stockholders' Equity - --------------------------------------------------------------------------------
(in thousands, except per share amounts)
See accompanying notes to consolidated financial statements.
XTO ENERGY INC. Notes to Consolidated Financial Statements - --------------------------------------------------------------------------------
1. Organization and Summary of Significant Accounting Policies
XTO Energy Inc., a Delaware corporation, was organized under the name Cross Timbers Oil Company 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 and changed its name to XTO Energy Inc. in June 2001.
The accompanying consolidated financial statements include the financial statements of XTO Energy Inc. 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 September 18, 2000 and June 5, 2001.
The Company is an independent oil and gas company with production and exploration concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico, Wyoming, Alaska and Louisiana. The Company also gathers, processes and markets gas, transports and markets oil and conducts other activities directly related to its oil and gas producing activities.
Property and Equipment
The Company follows the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. The Company generally pursues acquisition and development of proved reserves as opposed to exploration activities. Most of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of producing properties from other oil and gas companies. Producing properties balances include costs of $136,611,000 at December 31, 2001 and $66,823,000 at December 31, 2000, related to wells in process of drilling.
Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives which range from 3 to 40 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized. The estimated undiscounted cost, net of salvage value, of dismantling and removing major oil and gas production facilities, including necessary site restoration, is accrued using the unit-of-production method.
If conditions indicate that long-term assets may be impaired, the carrying value of property and equipment is compared to management's future estimated pretax cash flow. If impairment is necessary, the asset carrying value is adjusted to fair value. Cash flow pricing estimates are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Impairment of individually significant undeveloped properties is assessed on a property-by-property basis, and impairment of other undeveloped properties is assessed and amortized on an aggregate basis.
Royalty Trusts
The Company created Cross Timbers Royalty Trust in February 1991 and Hugoton Royalty Trust in December 1998 by conveying defined net profits interests in certain of the Company's properties. Units of both trusts are traded on the New York Stock Exchange. The Company makes monthly net profits payments to each trust based on revenues and costs from the related underlying properties. The Company owns 22.7% of Cross Timbers Royalty Trust units that it purchased on the open market in 1996 and 1997, and owns 54.3% of the Hugoton Royalty Trust following the sale of units in 1999 and 2000. The cost of the Company's interest in the trusts is included in producing properties. Amounts due the trusts, net of amounts retained by the Company's ownership of trust units, are deducted from the Company's revenues, taxes, production expenses and development costs.
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.
Investment in Equity Securities
In accordance with Statement of Financial Accounting Standards ("SFAS") No. 115, Accounting for Certain Investments in Debt and Equity Securities, equity securities held during 1999 and 2000 were recorded as trading securities since they were acquired principally for resale in the near future. Accordingly, unrealized holding gains and losses are recognized in the consolidated income statements, and cash flows from purchases and sales of equity securities are included in cash provided by operating activities in the consolidated statements of cash flows. Gains (losses) on trading securities and interest expense related to the cost of these investments are classified as other income (expense) in the consolidated income statements.
Other Assets
Other assets primarily include deferred debt costs that are amortized over the term of the related debt (Note 3) and the long-term portion of gas balancing receivable (see "Revenue Recognition" below). Other assets are presented net of accumulated amortization of $16,194,000 at December 31, 2001 and $11,574,000 at December 31, 2000.
Derivatives
The Company uses derivatives to hedge product price and interest rate risks, as opposed to their use for trading purposes. On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138 (Note 6). SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the income statement. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. Physical delivery contracts which are not expected to be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives. However, physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative (Note 8).
Gains and losses on commodity hedge derivatives are recognized in oil and gas revenues when the hedged transaction occurs, and gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Cash flows related to derivative transactions are included in operating activities.
In conjunction with its hedging activities, the Company occasionally enters natural gas call options. Because options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectively provided by the call options, is recognized as a derivative fair value loss, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged production occurs, as prescribed by hedge accounting.
Revenue Recognition
The Company uses the entitlement method of accounting for gas sales, based on the Company's net revenue interest in production. Accordingly, revenue is deferred for gas deliveries in excess of the Company's net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. The consolidated balance sheets include the following amounts related to production imbalances:
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 $108,590,000 for 2001, $144,282,000 for 2000 and $66,175,000 for 1999. These amounts are net of intercompany eliminations.
Other Revenues
Other revenues include gains and losses from sale of property and equipment. Excluding the gain on sale of significant property divestitures, including the sale of Hugoton Royalty Trust units, the Company realized a net loss on sale of property and equipment of $277,000 in 2001, and a net gain on sale of property and equipment of $920,000 in 2000 and $6,390,000 in 1999.
Interest
Interest expense includes amortization of deferred debt costs and is presented net of interest income of $716,000 in 2001, $1,430,000 in 2000 and $619,000 in 1999, and net of capitalized interest of $6,649,000 in 2001, $3,488,000 in 2000 and $1,353,000 in 1999. Interest is capitalized as producing property cost based on the weighted average interest rate and the cost of wells in process of drilling. Interest expense related to investment in equity securities has been classified as a component of gain (loss) on investment in equity securities.
Stock-Based Compensation
In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation is recorded for stock options or other stock-based awards that are granted to employees or non- employee directors with an exercise price equal to or above the common stock price on the grant date. Compensation related to performance share grants with time vesting conditions is based on the fair value of the award at the grant date and recognized over the vesting period. Compensation related to performance shares with price target vesting is recognized when the price target is reached. The pro forma effect of recording stock-based compensation at the estimated fair value of awards on the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, is disclosed in Note 12.
Earnings per Common Share
In accordance with SFAS No. 128, Earnings Per Share, the Company reports basic earnings per share, which excludes the effect of potentially dilutive securities, and diluted earnings per share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. See Note 10.
Segment Reporting
In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, the Company has identified only one operating segment, which is the exploration and production of oil and gas. All the Company's assets are located in the United States and all its revenues are attributable to United States customers.
Production is sold under contracts with various purchasers. For the year ended December 31, 2001, sales to each of three purchasers were approximately 13%, 12% and 10% of total revenues. For the year ended December 31, 2000, sales to a single purchaser were approximately 13% of total revenues. There were no sales to a single purchaser that exceeded 10% of total revenues in 1999. The Company believes that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these significant purchasers.
2. Related Party Transactions
Loans to Officers
Pursuant to margin support agreements with each of six officers, the Company, with Board of Director authorization, agreed to use up to $15 million of the value of Cross Timbers Royalty Trust units owned by the Company and the investment in equity securities to provide margin support for the officers' broker accounts in which they held Company common stock. The Company also agreed to pay, if necessary, each officer's margin debt in the event the officer subsequently failed to satisfy the debt. In connection with these agreements, in December 1998 the Company loaned four officers a total of $5,795,000 to reduce their margin debt. An additional $1,530,000 was loaned during 1999, including a new loan to a fifth officer. The loans were full recourse and due in December 2003, with an interest rate equal to the Company's bank debt rate. In May 2001, officers sold 302,000 shares of common stock to the Company for $6,496,000 and used the proceeds to partially repay their loans. Loans to officers were fully repaid in November 2001.
Other Transactions
A company, partially owned by a director of the Company, received fees totaling $994,000 in 2000 for consulting services performed in connection with the Company's acquisition and divestiture programs. The director-related company also represented the purchaser of properties sold by the Company during 1999 and invested in the purchase.
The same director-related company performed consulting services in connection with a 1998 acquisition and was entitled to receive, at its election, either a 20% working interest or a 1% overriding royalty interest conveyed from the Company's 100% working interest in the properties after payout of acquisition and operating costs. The Board of Directors authorized the purchase of this potential interest from the director-related company and other parties in November 2001 for $15 million, as supported by a third-party fairness opinion. The director-related company received $10 million of the total purchase price.
3. Debt
The Company's outstanding debt consists of the following:
Senior Debt
In May 2000, the Company entered a revolving credit agreement with commercial banks with a commitment of $800 million. In June 2000, the loan agreement was amended to allow the Company to issue letters of credit. Any letters of credit outstanding reduce the borrowing capacity under the revolving credit facility. As of December 31, 2001, there were no letters of credit outstanding. In February 2001, the loan agreement was amended to allow the repurchase of the Company's subordinated debt and to increase commodity hedging limits. In May 2001, the loan agreement was amended to allow the Company to issue senior debt. Borrowings at December 31, 2001 under the loan agreement were $556 million with unused borrowing capacity of $244 million. The borrowing base is redetermined annually based on the value and expected cash flow of the Company's proved oil and gas reserves. If borrowings exceed the redetermined borrowing base, the banks may require that the excess be repaid within a year. Based on reserve values at December 31, 2001 and using parameters specified by the banks, the borrowing base remains in excess of the $800 million commitment. Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at any time without penalty. The Company may renegotiate the loan agreement to increase the borrowing commitment and extend the revolving facility.
The credit facility is partially secured by the Company's producing properties. Restrictions set forth in the loan agreement include limitations on the incurrence of additional indebtedness and the creation of certain liens. The loan agreement also limits dividends to 25% of cash flow from operations, as defined, for the latest four consecutive quarterly periods. The Company is also required to maintain a current ratio of not less than one (where unused borrowing commitments are included as a current asset and current assets and liabilities related to derivative fair value are excluded).
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, 2001 were based on LIBOR rates with maturity of one to six months and accrued at the applicable LIBOR rate plus 1.375%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. The Company also incurs a commitment fee on unused borrowing commitments which was 0.25% at December 31, 2001. The weighted average interest rate on senior debt was 5.7% during 2001, 8.2% during 2000 and 6.7% during 1999.
Subordinated Debt
The Company sold $125 million of 9 1/4% senior subordinated notes on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes on October 28, 1997. The notes are general unsecured indebtedness that is subordinate to bank borrowings under the loan agreement. Net proceeds of $121.1 million from the 9 1/4% notes and $169.9 million from the 8 3/4% notes were used to reduce bank borrowings under the loan agreement. The 9 1/4% notes mature on April 1, 2007 and interest is payable each April 1 and October 1, while the 8 3/4% notes mature on November 1, 2009 with interest payable each May 1 and November 1.
The Company has the option to redeem the 9 1/4% notes on April 1, 2002 and the 8 3/4% notes on November 1, 2002 at a price of approximately 105%, and thereafter at prices declining ratably at each anniversary to 100% in 2005. Upon a change in control of the Company, the noteholders have the right to require the Company to purchase all or a portion of their notes at 101% plus accrued interest.
The notes were issued under indentures that place certain restrictions on the Company, including limitations on additional indebtedness, liens, dividend payments, treasury stock purchases, disposition of proceeds from asset sales, transfers of assets and transactions with subsidiaries and affiliates.
See Note 6 regarding interest rate swap agreements. Under the terms of one of these agreements, the Company has notified the bank counterparty that it will purchase subordinated notes with a face value of $9,725,000 on April 1, 2002. Including the effects of the interest swap agreement and expensing of related deferred debt cost, the Company will record a loss on extinguishment of debt of approximately $600,000.
4. Income Tax
The effective income tax rate for the Company was different than the statutory federal income tax rate for the following reasons:
Components of income tax expense are as follows:
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 liability of $27,330,000 and a long-term liability of $199,091,000 at December 31, 2001, and a current asset of $17,098,000 and a long- term liability of $82,476,000 at December 31, 2000. Significant components of net deferred tax assets and liabilities are:
As of December 31, 2001, the Company has estimated tax loss carryforwards of approximately $195 million, of which $10.6 million are related to capital losses. The capital loss tax carryforwards expire in 2005 while the remaining ordinary loss carryforwards are scheduled to expire in 2009 through 2021. Approximately $22 million of the tax loss carryforwards are the result of an acquisition. A new tax law, signed in March 2002 and retroactive to September 11, 2001, will increase the Company's tax loss carryforward by approximately $12 million. The Company has not booked any valuation allowance because it believes it has tax planning strategies available to realize its tax loss carryforwards.
5. Commitments and Contingencies
Leases
The Company leases offices, vehicles, airplanes, compressors and certain other equipment in its primary locations under noncancelable operating leases. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2001, minimum future lease payments for all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows:
Amounts incurred under operating leases (including renewable monthly leases) were $20,561,000 in 2001, $17,329,000 in 2000 and $14,093,000 in 1999.
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 with fixed renewal options for an additional 13 years at a total cost of $7.8 million. This transaction was recorded as a sale and operating leaseback, with no gain or loss on the sale.
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 ten years. Rentals are adjusted monthly based on the 30-day LIBOR rate and may be irrevocably fixed by the Company with 20 days advance notice. As of December 31, 2001, annual rentals were $1.6 million. This transaction was recorded as a sale and operating leaseback, with a deferred gain of $3.4 million on the sale. The deferred gain is amortized over the lease term based on pro rata rentals and is recorded in other long-term liabilities in the accompanying consolidated balance sheets. The deferred gain balance at December 31, 2001 was $1.6 million.
Under each of the above sale and leaseback transactions, the Company does not have the right or option to purchase, nor does the lessor have the obligation to sell the facility at any time. However, if the lessor decides to sell the facility at the end of the initial term or any renewal period, the lessor must first offer to sell it to the Company at its fair market value. Additionally, the Company has a right of first refusal of any third party offers to buy the facility after the initial term.
Employment Agreements
Two executive officers have year-to-year employment agreements with the Company. The agreements are automatically renewed each year-end unless terminated by either party upon thirty days notice prior to each December 31. Under these agreements, the officers receive a minimum annual salary of $625,000 and $450,000, respectively, and are entitled to participate in any incentive compensation programs administered by the Board of Directors. The agreements also provide that, in the event the officer terminates his employment for good reason, as defined in the agreement, the Company terminates the employee without cause or a change in control of the Company occurs, the officer is entitled to a lump-sum payment of three times the officer's most recent annual compensation. In addition, the officer is entitled to receive a payment sufficient to make the officer whole for any excise tax on excess parachute payments imposed by the Internal Revenue Code.
Commodity Commitments
The Company has entered into natural gas physical delivery contracts, futures contracts, collars and swap agreements that effectively fix gas prices. See Note 8.
Drilling Contracts
The Company has agreements to use four drilling rigs and one workover rig through July 2003. Total commitments under these agreements are $9.5 million for 2002 and $1 million for 2003.
Litigation
On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against the Company in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which the Company has assumed the obligation to pay royalties. The plaintiffs allege that the Company has reduced royalty payments by post-production deductions and has entered into contracts with subsidiaries that were not arm's-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by the Company in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. The Company contends that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm's-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. The Company further contends that any such fees enhance the value of the gas or the products derived from the gas. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. A hearing on the class certification issue has not been scheduled. The court has ordered that the parties enter into mediation, which should occur in the first half of 2002. Management believes it has strong defenses against this claim and intends to vigorously defend the action. Management's estimate of the potential liability from this claim has been accrued in the Company's financial statements.
On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against the Company and certain of its subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that the Company underpaid royalties on gas produced from federal leases and lands owned by Native Americans by at least 20% during the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. According to the U.S. Department of Justice, the plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for the Company to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against the Company and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. The Company and other defendants filed a motion to dismiss the lawsuit, which was denied. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in the Company's financial statements.
In February 2000, the Department of Interior notified the Company and several other producers that certain Native American leases located in the San Juan Basin have expired due to the failure of the leases to produce in paying quantities from February through August 1990. The Department of Interior has demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. The Company has filed a Notice of Appeal with the Interior Board of Indian Appeals. 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.
In June 2001, the Company was served with a lawsuit styled Quinque Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against the Company and one of its subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. No class has been certified. The allegations in the case are similar to those in the Grynberg case; however, the Quinque case broadens the claims to cover all oil and gas leases (other than the Federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines resulting in underpayments to the plaintiffs. Plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In September 2001, the Company filed a motion to dismiss the lawsuit, which is currently pending. In February 2002, the Company and one of its subsidiaries were dismissed from the suit and another subsidiary of the Company was added. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in the Company's financial statements.
The Company is involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on the Company's financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.
Other
To date, the Company's expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
6. Financial Instruments
The Company uses financial and commodity-based derivative contracts to manage exposures to commodity price and interest rate fluctuations. The Company does not hold or issue derivative financial instruments for speculative or trading purposes.
Change in Accounting Principle
On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138, by recording a one-time after-tax charge of $44,589,000 in the income statement for the cumulative effect of a change in accounting principle and an unrealized loss of $67,323,000 in accumulated other comprehensive income. The unrealized loss is related to the derivative fair value of cash flow hedges. The charge to the income statement is primarily related to the Company's physical delivery contract with crude oil-based pricing, also referred to as the Enron Btu swap contract.
After adoption of SFAS No. 133, all derivative financial instruments are recorded on the balance sheet at fair value. Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, are recorded in derivative fair value gain (loss) in the income statement. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income, which is later transferred to earnings when the hedged transaction occurs.
Enron Btu Swap Contract
In 1995, the Company entered a contract to sell gas based on crude oil pricing, also referred to as the Enron Btu swap contract (Note 8). This contract was terminated as a result of the Enron bankruptcy (Note 7). Because the contract pricing is not clearly and closely associated with natural gas prices, it must be considered a non-hedge derivative financial instrument under SFAS No. 133 beginning January 1, 2001, with changes in fair value recorded as a derivative gain (loss) in the income statement.
Prior to termination of the Enron Btu swap contract, the Company entered derivative contracts with another counterparty to effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. Changes in fair value of these contracts are recorded as a derivative gain (loss) in the income statement. In March 2002, the Company terminated some of these contracts with maturities of May through December 2002 and received $6.6 million from the counterparty. Because these contracts are non-hedge derivatives, most of the related $6.6 million gain related to their termination was recorded in 2001 derivative fair value gain.
Commodity Price Hedging Instruments
The Company periodically enters into futures contracts, energy swaps, collars and basis swaps to hedge its exposure to price fluctuations on crude oil and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts, the Company pays this excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, the Company receives this difference from the counterparty. The Company has hedged its exposure to variability in future cash flows from natural gas sales for transactions occurring through December 2002. See Note 8.
In 2001, net losses on futures and basis swap hedge contracts reduced gas revenue by $11.1 million. Including the effect of fixed price physical delivery contracts, all hedging activities increased gas revenue by $97 million. During 2000, net losses on futures and basis swap hedge contracts reduced gas revenue by $40.5 million and oil revenue by $7.8 million. During 1999, net losses on futures and basis swap hedge contracts reduced gas revenue by $5.7 million and oil revenue by $2.2 million. The effect of fixed price physical delivery contracts was not significant in 2000 or 1999. As of December 31, 2001, an unrealized pre-tax derivative fair value gain of $108.7 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income. The ultimate settlement value of these hedges will be recognized in the income statement as gas revenue when the hedged gas sales occur over the next year.
The Company occasionally sells gas call options. Because these options are covered by Company production, they have the same effect on the Company as product hedges when the strike prices are below current market gas prices. However, because written options do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectively provided by the call options, has been recognized as a loss in derivative fair value, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged production occurs.
Interest Rate Swap Agreements
To reduce the interest rate on a portion of its subordinated debt, the Company entered an agreement with a bank to purchase a portion of the Company's subordinated notes with a face value of $21.6 million. The Company pays the bank a variable interest rate based on three-month LIBOR rates, and receives semiannually from the bank the fixed interest rate on the notes. The term of the agreement for approximately half the notes is through April 2002, and for the remaining half is through November 2002. Any depreciation in market value of the notes from the date purchased by the bank is immediately payable to the bank. Any appreciation in the market value, including any depreciation payments, is receivable from the bank to the extent of the market value of the notes at the end of the agreement. The Company has the option of terminating this agreement and purchasing the notes from the bank at any time at market value. The Company has notified the bank that it will purchase subordinated notes with a face value of $9,725,000 on April 1, 2002, the termination date of the related interest swap agreement. See Note 3. This agreement is recorded in the financial statements as a non-hedge derivative with changes in fair value recorded in the income statement.
In September 1998, to reduce variable interest rate exposure on debt, the Company entered into a series of interest rate swap agreements, effectively fixing its interest rate at an average of 6.9% on a total notional balance of $150 million until September 2005. In 1999 and 2000, the Company terminated these interest rate swaps, resulting in a gain of $2 million. This gain has been deferred and is being amortized against interest expense through September 2005.
Derivative Fair Value (Gain) Loss
The components of derivative fair value (gain) loss, as reflected in the consolidated income statements are:
Fair Value of Financial Instruments
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, 2001 and 2000. The following are estimated fair values and carrying values of the Company's other financial instruments at each of these dates:
(a) These contracts were entered prior to termination of the Enron Btu swap contract and effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract.
(b) In March 2002, the Company terminated contracts with maturities of May through December 2002 and received $6.6 million from the counterparty. Because these contracts are non-hedge derivatives, most of the related $6.6 million gain related to their termination was recorded in 2001 derivative fair value gain.
(c) The Enron Btu swap contract was terminated in December 2001 (Note 7). The value of this contract immediately prior to termination was a $43.3 million liability, which is recorded as a current liability until legal extinguishment is finalized.
The fair value of bank borrowings approximates their carrying value because of short-term interest rate maturities. The fair value of subordinated long-term debt is based on current market quotes. The fair value of futures contracts, swap agreements and call options is estimated based on the exchange- trade value of NYMEX contracts, market commodity prices and interest rates for the applicable future periods.
Changes in fair value of derivative assets and liabilities are the result of changes in oil and gas prices and interest rates. Natural gas futures and swaps are generally designated as hedges of commodity price risks, and accordingly, changes in their values are predominantly recorded in accumulated other comprehensive income until the hedged transaction occurs.
During 2001, the Company entered gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives; therefore, the contracts are not required to be recorded in the financial statements. The value of outstanding physical delivery contracts at December 31, 2001 was $36.4 million.
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. Financial and commodity-based swap contracts expose the Company to the credit risk of non-performance by the counterparty to the contracts. In general, the Company does not believe this risk is significant since the exposure is diversified among major banks and financial institutions with high credit ratings. See Note 7 regarding credit risk related to the Enron Corporation bankruptcy. 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
$4,098,000 at December 31, 2001 and $3,121,000 at December 31, 2000. The Company's bad debt provision was $978,000 in 2001, $1,093,000 in 2000 and $1,347,000 in 1999.
7. Enron Corporation Bankruptcy
As of December 2, 2001, the date of its bankruptcy filing, Enron Corporation was the counterparty to some of the Company's hedge derivative contracts, as well as a purchaser of natural gas under certain physical delivery contracts. One of these contracts was a natural gas physical delivery contract with crude oil-based pricing ("Enron Btu swap contract").
The Company sent Enron notices of contract terminations in November and December 2001. Based on the fair value as of the contract termination dates, Enron owes the Company $7.8 million for physical gas deliveries in November and December 2001, and $13.5 million for net gains on hedge derivative contracts. Enron also owes the Company $14.1 million in net unrealized gains related to undelivered gas under physical delivery contracts. This amount, however, will not be recorded in the financial statements until collectibility is assured.
Also recorded in the balance sheet at December 31, 2001 is a current liability of $43.3 million related to the Enron Btu swap contract, based on fair values at the date of contract termination. As specified under the contract termination provisions, the Company, as the nondefaulting party, has notified Enron that its liability under this contract has been reduced to zero. Based upon discussion with outside legal counsel, the Company believes that these termination provisions are legally enforceable, and accordingly, it has no liability under this contract. However, under generally accepted accounting principles, this liability cannot be credited to income until legal extinguishment of the debt is finalized.
In the event the termination provisions of the Enron Btu swap contract are ultimately not enforced, the Company believes that, based on contract provisions and discussions with outside legal counsel, it should have the right to offset all amounts due from Enron against any Enron Btu swap contract liability, including amounts related to undelivered gas under physical delivery contracts. Because the recorded Enron Btu swap contract liability exceeds total Enron receivables at December 31, 2001, no reserve for asset collectibility has been recorded.
Final resolution of the Enron bankruptcy and related proceedings may result in a settlement materially different from amounts recorded at December 31, 2001. The following is a summary of recorded, unrecorded and total amounts related to Enron:
8. Natural Gas Sales Commitments
The Company has entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 6 regarding accounting for commodity hedges. All contracts with Enron have been terminated and excluded (Note 7). Futures Contracts and Swap Agreements -------------------------------------- NYMEX Price 2002 Production Period Mcf per Day per Mcf (a) ------------------------------- -------------------- --------------- April to May 355,000 $ 3.66 June 305,000 3.71 July to December 280,000 3.73
(a) Includes approximately $0.05 per Mcf gain that will be deferred and recognized in 2003 related to contract terminations and hedge redesignations.
The Company has entered into basis swap agreements which effectively fix basis for the following production and periods:
- -------------------
(a) Reductions from NYMEX gas price for location, quality and other adjustments.
The Company's settlement of futures contracts and basis swap agreements related to first quarter 2002 gas production resulted in increased gas revenue of $32.3 million. This gain will be recognized as an increase in gas revenue of approximately $0.75 per Mcf in the first quarter of 2002. Included in these settlements is $4.4 million related to terminated Enron futures contracts and swap agreements which will be recognized as an increase in gas revenue of approximately $0.10 per Mcf.
In December 2001 and March 2002, the Company closed futures contracts and swap agreements that were designated as cash flow hedges and, accordingly, has recorded deferred gains of $10.5 million in accumulated other comprehensive income. Included in these deferred gains is $7.6 million related to terminated Enron futures contracts. Deferred gains on these closed contracts will be recorded as gas revenue based on production in the following periods:
Production Period Mcf per Day Gain per Mcf/d - ------------------------------- -------------------- ------------------- 2002 April 50,000 $ 0.72 May 50,000 0.68 June 75,000 0.65 July 75,000 0.62 August 75,000 0.60 September 75,000 0.61 October 75,000 0.49 November 65,000 0.45 December 65,000 0.34
In March 2002, the Company entered into collar agreements which provide a floor (put) and ceiling (call) price for natural gas. If the market price of natural gas exceeds the call price or falls below the put price, the Company receives the fixed price and pays the market price. If the market price of natural gas is between the floor and ceiling price, no payments are due from either the Company or the counterparty. Prices to be realized may be less than these floor and ceiling prices because of location, quality and other adjustments. The Company has entered into collar agreements for the following production periods:
Average NYMEX Price (a) ------------------------ 2002 Production Period Mcf per Day Floor Ceiling - ------------------------------- ------------------- ----------- ----------- April to May 75,000 $ 2.60 $ 3.20 June 150,000 2.90 3.46 July to September 150,000 2.95 3.52 October to December 165,000 3.27 3.89
(a) Includes reduction of $0.10 per Mcf for cost of collars.
The Company has entered gas physical delivery contracts that are considered to be normal sales, and therefore, are not recorded in the financial statements, because they are not expected to be net cash settled. All Enron contracts have been terminated and excluded. These contracts effectively fix prices for the following production and periods:
Other Physical Delivery Contracts
From August 1995 through July 1998 the Company received an additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, the Company agreed to sell 34,344 Mcf per day at the index price in 2001 and 35,500 Mcf per day from 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. See Note 6 regarding accounting for this contract, also referred to as the Enron Btu swap contract, which has been terminated as a result of the Enron bankruptcy (Note 7). Also see Note 6 regarding a related derivative commitment with another counterparty.
As partial consideration for an acquisition, the Company agreed to sell gas volumes ranging from 40,000 Mcf in 2000 to 35,000 Mcf in 2003 at specified discounts from index prices. This commitment was recorded at its total value of $7.5 million in March 1999 in other current and long-term liabilities. The discounts are charged to the liability as taken. As of December 31, 2001, $1,552,000 is recorded in other current liabilities and $455,000 is recorded in other long-term liabilities related to this commitment.
As part of an acquisition, the Company assumed a commitment to sell 6,800 Mcf of gas per day in Arkansas through April 2003 at prices which are adjusted by the monthly index price. In 2001, the prices ranged from $0.44 to $1.44 per Mcf. This contract is considered a normal sale and therefore, is not recorded as a derivative in the Company's financial statements.
In 1998, the Company sold a production payment, payable from future production from certain properties acquired in an acquisition, to EEX Corporation for $30 million. Under the terms of the production payment conveyance and related delivery agreement, the Company committed to deliver to EEX a total of approximately 34.3 Bcf (27.8 Bcf net to the Company's interest) of gas during the 10-year period beginning January 1, 2002, with scheduled deliveries by year, subject to certain variables. EEX will reimburse the Company for all royalty and production and property tax payments related to such deliveries. EEX will also pay the Company an operating fee of $0.257 per Mcf for deliveries in 2002, which fee will be escalated annually at a rate of 5.5%. Each December, beginning in 1998, the Company had
the option to repurchase a portion of this production payment, based on a total cost of $30 million plus interest accrued from May 1, 1998 through the repurchase date. The Company repurchased portions of the production payment in 2001 and 2002 for $20.7 million (Note 13). According to the terms of the delivery agreement, the Company has the right to receive the repurchased production payment volumes first out of production commencing January 1, 2002. Because the Company has repurchased 18.3 Bcf (14.8 Bcf net) of gas, it should be approximately September 2006 before EEX will begin receiving the remaining 16.0 Bcf (13.0 Bcf net) of gas.
9. Equity
Three-for-Two Stock Splits
The Company effected three-for-two common stock splits on September 18, 2000 and June 5, 2001. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits.
Common Stock
The following reflects the Company's common stock activity:
In July 1999, the Company issued 9 million shares of common stock at its fair value of $5.08 per share in exchange for its 50% interest in an acquisition and for cash proceeds of $3.2 million which were used to reduce bank debt.
Also in July 1999, the Company sold from treasury 4.5 million shares of common stock in an underwritten public offering for net proceeds of approximately $26.5 million. The proceeds were used to repurchase 4.3 million shares of common stock issued in conjunction with an acquisition.
In May 2000, 13.3 million shares were canceled from treasury stock. This transaction caused a $71.5 million reduction in treasury stock with an offsetting reduction in additional paid-in capital, resulting in no change to total stockholders' equity.
In November 2000, the Company sold from treasury 9.9 million shares of common stock in an underwritten public offering for net proceeds of approximately $126.1 million. The proceeds were used to reduce bank debt.
Treasury Stock
The Company's open market treasury share acquisitions totaled 7.9 million shares in 2000 at an average price of $5.25 and 11,000 shares in 1999 at an average price of $4.69 per share. As of March 27, 2002, 6.5 million shares remain under the May 2000 Board of Directors' authorization to repurchase 6.8 million shares of the Company's common stock.
Stockholder Rights Plan
In August 1998, the Board of Directors adopted a stockholder rights plan that is designed to assure that all stockholders receive fair and equal treatment in the event of any proposed takeover of the Company. Under this plan, a dividend of one preferred share purchase right was declared for each outstanding share of common stock, par value $.01 per share, payable on September 15, 1998 to stockholders of record on that date. Each right entitles stockholders to buy one one-thousandth of a share of newly created Series A Junior Participating Preferred Stock at an exercise price of $80, subject to adjustment in the event a person acquires or makes a tender or exchange offer for 15% or more of the outstanding common stock. In such event, each right entitles the holder (other than the person acquiring 15% or more of the outstanding common stock) to purchase shares of common stock with a market value of twice the right's exercise price. At any time prior to such event, the Board of Directors may redeem the rights at one cent per right. The rights can be transferred only with common stock and expire in ten years.
Shelf Registration Statement
In October 2001, the Company filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities, preferred stock, common stock or warrants to purchase debt securities, preferred stock or common stock. The total price of securities to be offered is $600 million, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities are to be used for general corporate purposes, including reduction of bank debt. As of March 2002, no securities have been issued under the shelf registration statement.
Common Stock Warrants
As partial consideration for producing properties acquired in December 1997, the Company issued warrants to purchase 2.1 million shares of common stock at a price of $6.70 per share for a period of five years. These warrants were valued at $5.7 million and recorded as additional paid-in capital.
Common Stock Dividends
The Board of Directors declared quarterly dividends of $0.0045 per common share from 1999 through second quarter 2000, $0.0067 per common share for third quarter 2000 through first quarter 2001 and $0.01 per common share for the remainder of 2001. See Note 3 regarding restrictions on dividends.
Series A Convertible Preferred Stock
Series A convertible preferred stock is recorded in the accompanying December 31, 2000 consolidated balance sheet at its liquidation preference of $25 per share. During 2000, 50,000 shares of convertible preferred stock were converted into 243,000 shares of common stock. In January 2001, the Company sent notice to preferred stockholders that it would redeem all outstanding shares in February 2001 at a price of $25.94 per share plus accrued and unpaid dividends. Prior to the redemption date, 1.1 million outstanding shares of preferred stock were converted into 5.3 million common shares.
10. Earnings Per Share
The following reconciles earnings (numerator) and shares (denominator) used in the computation of basic and diluted earnings per share:
11. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash transactions (Notes 9 and 12):
. Conversion of 1.1 million shares of preferred stock to 5.3 million shares of common stock in 2001 and conversion of 50,000 shares of preferred stock to 243,000 shares of common stock in 2000
. Cancellation of 13.3 million shares of treasury stock in 2000
. Sale of Hugoton Royalty Trust units in 2000 in exchange for 743,000 shares of common stock valued at $11.3 million, and in 1999 in exchange for 111,000 shares of common stock valued at $700,000
. Purchase of a 50% interest in an acquisition in 1999 in exchange for 8.4 million shares of common stock, valued at $42.5 million
. Performance shares activity, including:
. Grants of 878,000 shares in 2001, 1,230,000 shares in 2000 and 319,000 shares in 1999 to key employees and nonemployee directors
. Vesting of 602,000 shares in 2001, 1,510,000 shares in 2000 and 27,000 shares in 1999
. Forfeiture of 9,000 shares in 2001 and 27,000 shares in 1999
. Receipt of common stock of 66,000 shares (valued at $967,000) in 2000 for the option price of exercised stock options
Interest payments in 2001 totaled $59,550,000 (including $6,649,000 of capitalized interest), $80,067,000 in 2000 (including $3,488,000 of capitalized interest) and $70,500,000 in 1999 (including $1,353,000 of capitalized interest). Net income tax refunds were $140,000 during 2001 and $322,000 during 1999; income tax payments were $1,085,000 in 2000.
12. Employee Benefit Plans
401(k) Plan
The Company sponsors a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. The Company matches employee contributions of up to 10% of wages. Employee contributions vest immediately while the Company's matching contributions vest 100% upon completion of three years of service. All employees over 21 years of age may participate. Company contributions under the plan were $3,884,000 in 2001, $3,226,000 in 2000 and $2,514,000 in 1999.
Post-Retirement Health Plan
Effective January 1, 2001, the Company adopted a retiree medical plan for employees who retire at age 55 or over with a minimum of five years full-time service. Benefits under the plan are the same as for active employees, and continue until the retired employee or the employee's dependents are eligible for Medicare or another similar federal health insurance program. All participants pay premiums as determined by the Company. Post-retirement medical benefits are not pre-funded by the Company, but are paid when incurred. The status of the Company's post-retirement health plan for 2001 is as follows:
(in thousands) 2001 -------- Change in benefit obligation: Benefit obligation at January 1 ............................... $ 804 Service cost ............................................... 221 Interest cost .............................................. 62 Actuarial loss ............................................. 1 Benefit payments ........................................... (10) -------- Benefit obligation at December 31 ............................. $ 1,078 ========
Amounts recognized in the consolidated balance sheet:
Funded status ................................................. $ (1,078) Unrecognized net actuarial gain ............................... (9) -------- Accrued benefit liability, as recognized in the consolidated balance sheet at December 31, 2001 ............ $ (1,087) ========
Components of net periodic benefit cost:
Service cost .................................................. $ 221 Interest cost ................................................. 62 Recognized prior service cost ................................. 804 -------- Net periodic benefit cost ....................................... $ 1,087 ========
The weighted average discount rate used by the Company in determining the accumulated post-retirement benefit obligation was 7.5%. For measurement purposes, the annual rate of increase in the covered health care benefits was assumed to range from 9% in 2001 to 6% in 2006 and beyond. A 1% change in the assumed health care cost trend rate would have approximately a $158,000 effect on total estimated service and interest cost and approximately a $417,000 effect on the post-retirement benefit obligation.
1994 and 1997 Stock Incentive Plans
Under the 1994 Stock Incentive Plan and the 1997 Stock Incentive Plan, a total of 5,063,000 shares of common stock may be issued under each plan to directors, officers and other key employees pursuant to grants of stock options or performance shares. At December 31, 2001, there are 1,341,000 shares available for grant under the 1994 Plan and 1,181,000 shares available for grant under the 1997 Plan. Options vest and become exercisable on terms specified when granted by the compensation committee ("the Committee") of the Board of Directors. Options granted under the 1994 Plan have a term of ten years and are not exercisable until six months after their grant date. Options granted under the 1997 plan have a term of ten years. 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. All outstanding options under the 1994 Plan were vested by resolution of the Board of Directors.
1998 Stock Incentive Plan
Under the 1998 Stock Incentive Plan, a total of 13,500,000 shares of common stock may be issued pursuant to grants of stock options or performance shares. Grants under the 1998 Plan are subject to the provision that outstanding stock options and performance shares under all the Company's stock incentive plans cannot exceed 6% of the Company's outstanding common stock at the time such grants are made. At December 31, 2001, there were 1,249,000 shares available for grant under the 1998 Plan. Stock options generally vest and become exercisable annually in equal amounts over a five-year period, with provision for accelerated vesting when the common stock price reaches specified levels. There were 44,000 options outstanding at December 31, 2001 that vest when the common stock price reaches $23.33, 174,000 options that vest when the common stock price reaches $21.50, 5,000 options that vest when the common stock price reaches $20.00 and 174,000 options that vest when the common stock price reaches $19.50. The options with the common stock target prices of $19.50 and $20.00 vested in March 2002.
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 common stockholders. The Company issued performance shares to key employees totaling 871,000 in 2001, 1,230,000 in 2000 and 292,000 in 1999. Performance shares vested, totaling 595,000 in 2001 and 1,510,000 in 2000, when the common stock price reached specified levels. In 2001, 9,000 of the performance shares issued in 2001 were forfeited, and in 1999, 27,000 performance shares issued in 1998 were forfeited. General and administrative expense includes compensation related to performance shares of $8.7 million in 2001, $18.4 million in 2000 and $102,000 in 1999. As of December 31, 2001, there were 159,000 performance shares that vest when the common stock price reaches $18.30, 242,000 performance shares that vest when the common stock price reaches $21.67 and 13,500 performance shares that vest in increments of 6,750 in each of 2002 and 2003. In February 2002, upon vesting of the performance shares with the $18.30 common stock vesting price, an additional 159,000 performance shares were issued that vested when the stock price reached $20.00 in March 2002. The Company also issued to nonemployee directors a total of 8,000 perfomance shares in February 2002, 7,000 performance shares in 2001 and 27,000 performance shares in 1999, all of which vested upon grant.
In 2001, the Board approved an agreement with certain executive officers under which the officers, immediately prior to a change in control of the Company, will receive a total grant of 150,000 performance shares for every $1.67 increment in the closing price of the Company's common stock above $20.00. Unless otherwise designated by the Board, the number of performance shares granted under the agreement will be reduced by the number of performance shares awarded to the officers between the date of the agreement and the date of the change in control. Certain officers will also receive a total grant of 232,500 performance shares immediately prior to a change in control without regard to the price of the Company's common stock.
Royalty Trust Option Plans
Under the 1998 Royalty Trust Option Plan, the Company granted certain officers options to purchase 1,290,000 Hugoton Royalty Trust units at prices of $8.03 and $9.50 per unit, or a total of $12 million. These options were exercised in 2000 and 1999, resulting in non-cash compensation expense of $7.1 million in 2000 and $60,000 in 1999.
Option Activity and Balances
The following summarizes option activity and balances from 1999 through 2001:
The following summarizes information about outstanding options at December 31, 2001:
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 $8.68 in 2001, $6.85 in 2000 and $2.85 in 1999.
Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair Value
The following are pro forma earnings available to common stock and earnings per common share for 2001, 2000 and 1999, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation:
(in thousands, except per share data)
13. Acquisitions and Dispositions
Acquisitions
In January 2001, the Company acquired gas properties in East Texas and Louisiana for $115 million from Herd Producing Company, Inc., and in February 2001, it acquired gas properties in East Texas for $45 million from Miller Energy, Inc. and other owners. In August 2001, the Company acquired primarily underdeveloped acreage in the Freestone area of East Texas for approximately $22 million. The purchases were funded with bank debt and are subject to typical post-closing adjustments.
Acquisitions have been recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for the year ended December 31, 2000 as if these acquisitions had been consummated immediately prior to January 1, 2000. Pro forma results are not presented for the year ended December 31, 2001 because the effects of these acquisitions excluded from 2001 results are not significant. These pro forma results are not necessarily indicative of future results.
(in thousands, except per share data)
Revenues .................................................... $620,113 ======== Net income .................................................. $115,231 ======== Earnings available to common stock .......................... $113,473 ======== Earnings per common share: Basic ..................................................... $ 1.06 ======== Diluted ................................................... $ 1.01 ======== Weighted average shares outstanding ......................... 106,730 ========
In January 2001, the Company repurchased 9.1 Bcf of natural gas for $9.9 million from a production payment sold to EEX Corporation in a 1998 acquisition. In January 2002, the Company repurchased an additional 9.2 Bcf of natural gas for $10.8 million. See Note 8.
In 1999, the Company and Lehman Brothers acquired the common stock of Spring Holding Company, a private oil and gas company, for a combination of cash and the Company's common stock totaling $85 million. The Company and Lehman each owned 50% of a limited liability company that acquired the common stock of Spring. In September 1999, the Company acquired Lehman's 50% interest in Spring for $44.3 million. This acquisition included oil and gas properties located in the Arkoma Basin of Arkansas and Oklahoma with a purchase price of $235 million. After purchase accounting adjustments and other costs, the cost of the properties was $257 million.
The Company also acquired in 1999, with Lehman as 50% owner, Arkoma Basin properties from affiliates of Ocean Energy, Inc. for $231 million. The Company acquired Lehman's interest in the Ocean Energy Acquisition in March 2000 for $111 million.
Dispositions
In June 2001, the Company and Cross Timbers Royalty Trust filed an amended registration statement with the Securities and Exchange Commission to sell 1,360,000 units (22.7% of outstanding units) owned by the Company. The Company's sale of these units is dependent upon commodity prices and related market conditions for oil and gas equities. These units are classified as producing properties in the accompanying balance sheet at a net cost of $12.2 million at December 31, 2001.
In March 2000, the Company sold producing properties in Crockett County, Texas, and Lea County, New Mexico for total gross proceeds of $68.3 million. In May and June 1999, the Company sold primarily nonoperated gas-producing properties in New Mexico for $44.9 million. In September 1999, the Company sold primarily nonoperated oil- and gas-producing properties in Oklahoma, Texas, New Mexico and Wyoming for $63.5 million, including sales of $22.5 million of properties acquired in the Spring Holding Company acquisition.
In December 1998, the Company formed the Hugoton Royalty Trust by conveying 80% net profits interests in properties located in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These net profits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. In April and May 1999, the Company sold 17 million, or 42.5%, of the trust units in an initial public offering at a price of $9.50 per unit, less underwriters' discount and expenses. Total net proceeds from the sale were $148.6 million, resulting in a gain of $40.3 million before income tax. Proceeds from the sale were used to reduce bank debt. In 1999 and 2000, officers exercised options to purchase a total of 1.3 million Hugoton Royalty Trust units from the Company pursuant to the 1998 Royalty Trust Option Plan in exchange for shares of Company common stock. The Company recognized gains of $11 million in 2000 and $235,000 in 1999 on these sales of trust units.
14. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2001 and 2000:
(a) Operating income before general and administrative expense.
15. 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) 2001 2000 1999 -------- -------- -------- Acquisitions: Producing properties ................ $238,041 $ 31,983 $505,912 Undeveloped properties .............. 3,980 3,490 4,182 Development (a) .......................... 385,479 163,224 89,306 Exploration: Geological and geophysical studies .. 2,123 829 872 Dry hole expense .................... 2,189 -- -- Rental expense and other ............ 1,126 218 32 -------- -------- --------
Total .................................... $632,938 $199,744 $600,304 ======== ======== ========
(a) Includes capitalized interest of $6,649,000 in 2001, $3,488,000 in 2000 and $1,353,000 in 1999.
Proved Reserves
The Company's proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.
Standardized Measure
The standardized measure of discounted future net cash flows ("standardized measure") and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits.
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.
(a) Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $1,947,441,000 in 2001, $7,748,632,000 in 2000 and $1,765,936,000 in 1999.
(a) Generally based on the year-end present value (at year-end prices and costs) plus the cash flow received from such properties during the year, rather than the estimated present value at the date of acquisition.
(b) Generally based on beginning of the year present value (at beginning of year prices and costs) less the cash flow received from such properties during the year, rather than the estimated present value at the date of sale.
Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.
Year-end realized oil prices used in the estimation of proved reserves and calculation of the standardized measure were $17.39 for 2001, $25.49 for 2000 and $24.17 for 1999. Year-end average realized gas prices were $2.36 for 2001, $9.55 for 2000 and $2.20 for 1999. Year-end average realized natural gas liquids prices were $8.70 for 2001, $26.33 for 2000 and $13.83 for 1999. Proved oil and gas reserves at December 31, 2001 include:
. 1,658,000 Bbls of oil and 204,123,000 Mcf of gas and discounted present value before income tax of $159,275,000 related to the Company's ownership of approximately 54% of Hugoton Royalty Trust units at December 31, 2001.
. 605,000 Bbls of oil and 7,305,000 Mcf of gas and discounted present value before income tax of $9,974,000 related to the Company's ownership of approximately 23% of Cross Timbers Royalty Trust units at December 31, 2001.
The standardized measure does not include the effect of hedge derivatives or fixed price physical delivery contracts. Including the effects of these contracts, the standardized measure before income tax would increase by $151.6 million at December 31, 2001 and $4.3 million at December 31, 1999, and would decrease by $193.8 million at December 31, 2000.
Based on assumed realized prices of $25.00 per Bbl for oil, $3.50 per Mcf for gas and $16.00 per Bbl for natural gas liquids, estimated proved reserves at December 31, 2001 would be 59.3 million Bbls of oil, 2.3 Tcf of natural gas and 22.3 million Bbls of natural gas liquids. Using these prices, the present value of estimated future cash flows, discounted at 10% and before income tax, would be $3.5 billion.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of XTO Energy Inc.
We have audited the accompanying consolidated balance sheets of XTO Energy Inc. and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated income statements, statements of cash flows and stockholders' equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As discussed in Note 6 to Consolidated Financial Statements, the Company changed its method of accounting for its derivative instruments and hedging activities effective January 1, 2001, in connection with its adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
ARTHUR ANDERSEN LLP
Fort Worth, Texas March 28, 2002
SCHEDULE II
XTO ENERGY INC. Consolidated Valuation and Qualifying Accounts - --------------------------------------------------------------------------------
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(a) Additions relate to provisions for doubtful accounts
(b) Deductions relate to the write-off of accounts receivable deemed uncollectible.
(c) Reclassification adjustment.
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 28th day of March 2002.
XTO ENERGY INC.
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 28th day of March 2002.
INDEX TO EXHIBITS
Documents filed prior to June 1, 2001 were filed with the Securities and Exchange Commission under the Company's prior name, Cross Timbers Oil Company.
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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, XTO Energy Inc., 810 Houston St., Suite 2000, Fort Worth, Texas 76102.